NC 0000789933-22-000015 10-K as filed: Mar 2, 2022

nacco-20211231

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K


(Mark One)
☑	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended	December 31, 2021


☐						TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No. 1-9172

NACCO INDUSTRIES, INC.

(Exact name of registrant as specified in its charter)

Delaware

34-1505819

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

5875 Landerbrook Drive,

Suite 220

Cleveland,

Ohio

44124-4069

(Address of principal executive offices)

(Zip Code)

Registrant's telephone number, including area code: (440) 229-5151

Securities registered pursuant to Section 12(b) of the Act

Title of each class

Trading Symbol

Name of each exchange on which registered

Class A Common Stock, $1 par value per share

New York Stock Exchange

Class B Common Stock is not publicly listed for trade on any exchange or market system; however, Class B Common Stock is convertible into Class A Common Stock on a share-for-share basis.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes ¨ No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes ¨ No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No £

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes þ No £

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☐

Accelerated filer

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Non-accelerated filer

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Smaller reporting company

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Emerging growth company

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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)

Yes ☐ No ☑

Aggregate market value of Class A Common Stock and Class B Common Stock held by non-affiliates as of June 30, 2021 (the last business day of the registrant's most recently completed second fiscal quarter): $109,032,630

Number of shares of Class A Common Stock outstanding at February 18, 2022: 5,616,768

Number of shares of Class B Common Stock outstanding at February 18, 2022: 1,566,413

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company's Proxy Statement for its 2022 annual meeting of stockholders are incorporated herein by reference in Part III of this Form 10-K.

NACCO INDUSTRIES, INC.

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			PAGE
PART I.
	Item 1.	BUSINESS	1
	Item 1A.	RISK FACTORS	20
	Item 1B.	UNRESOLVED STAFF COMMENTS	31
	Item 2.	PROPERTIES	31
	Item 3.	LEGAL PROCEEDINGS	43
	Item 4.	MINE SAFETY DISCLOSURES	43
PART II.
	Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	44
	Item 6.	SELECTED FINANCIAL DATA	44
	Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	45
	Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	60
	Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	60
	Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	60
	Item 9A.	CONTROLS AND PROCEDURES	60
	Item 9B.	OTHER INFORMATION	60
	Item 9C.	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	60
PART III.
	Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	61
	Item 11.	EXECUTIVE COMPENSATION	61
	Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	61
	Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	61
	Item 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	61
PART IV.
	Item 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	62
SIGNATURES			69
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			F-1

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PART I

Item 1. BUSINESS

General

NACCO Industries, Inc.® (“NACCO” or the “Company”) brings natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through its robust portfolio of NACCO Natural Resources businesses. The Company operates under three business segments: Coal Mining, North American Mining ("NAMining") and Minerals Management. The Coal Mining segment operates surface coal mines for power generation companies and an activated carbon producer. The NAMining segment is a trusted mining partner for producers of aggregates, lithium and other minerals. The Minerals Management segment, which includes the Catapult Mineral Partners (“Catapult”) business, acquires and promotes the development of mineral interests. In addition, Mitigation Resources of North America® (“Mitigation Resources”) provides stream and wetland mitigation solutions.

The Company has items not directly attributable to a reportable segment that are not included as part of the measurement of segment operating profit, which primarily includes administrative costs related to public company reporting requirements at the parent company and the financial results of Mitigation Resources and Bellaire Corporation ("Bellaire"). Bellaire manages the Company’s long-term liabilities related to former Eastern U.S. underground mining activities.

NACCO was incorporated as a Delaware corporation in 1986 in connection with the formation of a holding company structure for a predecessor corporation organized in 1913.

Business Strategy

During 2021, the Company launched a new branding campaign. The new branding creates a unified identity and underscores NACCO’s commitment to all of its businesses, while focusing on the execution of its two key strategies – Protect the Core and Grow and Diversify. NACCO’s portfolio of businesses now operates under the umbrella of NACCO Natural Resources. The new branding provides each business with its own unique identity that can easily be linked back to the NACCO legacy brand and includes new websites for each business, including NACCO Natural Resources, new business-specific logos and a new tagline “Bringing Natural Resources to Life”.

The Company is pursuing growth and diversification by strategically leveraging its core mining and natural resources management skills to build a strong portfolio of affiliated businesses. Management continues to be optimistic about the long-term outlook for growth in the NAMining and Minerals Management segments and in the Company's Mitigation Resources business. Each of these businesses continues to expand its pipeline of potential new projects with opportunities for growth and diversification.

The Minerals Management segment continues to grow and diversify by selectively acquiring mineral and royalty interests in the United States, in a market and price environment that the Company believes remains well-aligned with its strategy and objectives. The Minerals Management segment will benefit from the continued development of its mineral properties without additional capital investment, as all further development costs are borne entirely by third-party producers who lease the minerals. The Company believes this business model can deliver substantial operating margins over the life of a reserve without the costs and risk that traditional oil and gas companies bear for the cost of exploration, production and/or development. Catapult, the Company’s business unit focused on managing and expanding the Company’s portfolio of oil and gas mineral and royalty interests, has developed a strong network to source and secure new acquisitions, and has several potential acquisitions under review. The goal is to construct a diversified portfolio of high-quality oil and gas mineral and royalty interests in the United States that deliver near-term cash flow yields and long-term projected growth. The Company believes this business will provide unlevered after-tax returns on invested capital in the low-to-mid-teens as the portfolio of reserves and mineral interests grows and this business model matures.

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goal is to grow Mitigation Resources into one of the ten largest U.S. providers of mitigation solutions, largely focused on streams and wetlands, initially in the southeast United States. While this business is in the early stages of development, the Company believes that Mitigation Resources can provide solid rates of return as this business matures.

The Company also continues to pursue activities which can strengthen the resiliency of its existing coal mining operations. The Company remains focused on managing coal production costs and maximizing efficiencies and operating capacity at mine locations to help customers with management fee contracts be more competitive. These activities benefit both customers and the Company's Coal Mining segment, as fuel cost is a significant driver for power plant dispatch. Increased power plant dispatch results in increased demand for coal by the Coal Mining segment's customers. Fluctuating natural gas prices and availability of renewable energy sources, such as wind and solar, affect the amount of electricity dispatched from coal-fired power plants. Coal and natural gas traditionally have been the two largest sources of electricity generation in the United States. In many areas of the country, these two fuels compete to supply electricity based on their relative costs. U.S. natural gas prices have been more volatile than coal prices, so the cost of natural gas often determines the relative share of generation provided by natural gas and coal. Between 2015 and 2020, the cost of natural gas delivered to electric generators remained relatively low and stable. During 2021, however, natural gas prices were much higher than in recent years, generally resulting in increased dispatch of coal-fired power plants.

The Company continues to look for opportunities to expand its coal mining business where it can apply its management fee business model to assume operation of existing surface coal mining operations in the United States. However, opportunities are very limited in the current environment. In addition, the political and regulatory environment is not receptive to development of new coal-fired power generation projects which would create opportunities to build and operate new coal mines.

The Company is committed to maintaining a conservative capital structure as it continues to grow and diversify, while avoiding unnecessary risk. Strategic diversification will generate cash that can be re-invested to strengthen and expand the businesses. In all of its business endeavors, the Company continues to maintain the highest levels of customer service and operational excellence, with an unwavering focus on safety, environmental stewardship and people. The Company is passionately committed to working hard, doing what’s right, and bringing America's natural resources to life.

Business Developments

Coal Mining Segment

Effective September 30, 2021, the contract mining agreement between Bisti Fuels Company, LLC (“Bisti”) and its customer, Navajo Transitional Energy Company ("NTEC") was terminated. As required under the agreement, NTEC paid the Company a termination fee of $10.3 million. As of October 1, 2021, NTEC assumed control and responsibility for operation and all reclamation of the Navajo Mine.

The Coteau Properties Company (“Coteau”) operates the Freedom Mine in North Dakota. All coal production from the Freedom Mine is delivered to Basin Electric Power Cooperative (“Basin Electric”). Basin Electric utilizes the coal at the Great Plains Synfuels Plant (the “Synfuels Plant”), Antelope Valley Station and Leland Olds Station. The Synfuels Plant is a coal gasification plant, owned by Dakota Gasification Company (“Dakota Gas’), a subsidiary of Basin Electric, that manufactures synthetic natural gas and produces fertilizers, solvents, phenol, carbon dioxide, and other chemical products for sale. During 2020, Basin Electric informed Coteau that it is considering changes that may result in modifications to its Synfuels Plant that could potentially reduce or eliminate coal requirements at the Synfuels Plant. During August 2021, Bakken Energy (“Bakken”) and Basin Electric signed a non-binding term sheet to transfer ownership of the assets of Dakota Gas to Bakken. Bakken stated the closing date is expected to be April 1, 2023. As part of the term sheet between Basin Electric and Bakken, Basin Electric indicated that the Synfuels Plant will continue existing operations through 2025. The closing is subject to the satisfaction of specified conditions. Basin Electric is also considering other options for the Synfuels Plant if the transaction with Bakken does not close. Basin Electric indicated that if it decides to proceed with any changes that could reduce or eliminate the use of coal, the feedstock change is not expected to occur before 2026.

The Falkirk Mining Company ("Falkirk") operates the Falkirk Mine in North Dakota. Falkirk is the sole supplier of lignite coal to the Coal Creek Station power plant pursuant to a contract under which Falkirk also supplies approximately 0.3 million tons of lignite coal per year to Spiritwood Station power plant. Coal Creek Station and Spiritwood Station are owned by Great River Energy (“GRE”). In May 2020, GRE announced its intent to sell or retire Coal Creek Station and modify Spiritwood Station to be fueled by natural gas.

During June 2021, GRE entered into an agreement to sell Coal Creek Station and the adjacent high-voltage direct current transmission line to Bismarck, North Dakota-based Rainbow Energy Center, LLC (“Rainbow Energy”) and its affiliates. The

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closing of this sale is subject to the satisfaction of certain conditions and presently, the transaction is expected to close in the second quarter of 2022.

Upon completion of the sale of Coal Creek Station, the existing Coal Sales Agreement, the existing Mortgage and Security Agreement and the existing Option Agreement between GRE and Falkirk will terminate. Falkirk and GRE have entered into a termination and release of claims agreement. Upon completion of the sale of Coal Creek Station, GRE will pay Falkirk $14.0 million in cash, as well as transfer ownership of an office building located in Bismarck, North Dakota, and convey membership units in Midwest AgEnergy to The North American Coal Corporation® (“NACoal”), a wholly-owned subsidiary of NACCO. NACCO currently holds a $5.0 million investment in Midwest AgEnergy, which operates two ethanol facilities in North Dakota.

If GRE's efforts to sell the power plant are successful, a new Coal Sales Agreement (“CSA”) between Falkirk and Rainbow Energy will become effective and Falkirk will supply all coal requirements of Coal Creek Station concurrent with Rainbow Energy’s acquisition of the power plant. Falkirk will no longer make any coal deliveries to GRE’s Spiritwood Station. Falkirk will be paid a management fee and Rainbow Energy will be responsible for funding all mine operating costs and directly or indirectly providing all of the capital required to operate the mine. The CSA specifies that Falkirk will perform final mine reclamation, which will be funded in its entirety by Rainbow Energy. The initial production period is expected to run ten years from the effective date of the CSA, but the CSA may be extended or terminated early under certain circumstances. If Rainbow Energy terminates the CSA and closes Coal Creek Station before 2027, Falkirk will be entitled to an additional payment from GRE under the terms of the termination and release of claims agreement. The additional payment amount ranges from $8 million if the closure occurs before 2024 to $2 million if the closure occurs in 2026. To support the transfer to new ownership, Falkirk has agreed to a reduction in the current per ton management fee from the effective date of the new CSA through May 31, 2024. After May 31, 2024, the per ton management fee increases to a higher base in line with current fee levels, and thereafter adjusts annually according to an index which tracks broad measures of U.S. inflation.

If GRE’s efforts to sell the power plant are not successful and GRE elects to prematurely close Coal Creek Station, the early termination of the CSA would have a material adverse effect on the Company's business, financial condition and results of operations.

The Sabine Mining Company (“Sabine”) operates the Sabine Mine in Texas. All production from Sabine is delivered to Southwestern Electric Power Company's (“SWEPCO”) Henry W. Pirkey Plant (the “Pirkey Plant”). SWEPCO is an American Electric Power (“AEP”) company. During 2020, AEP announced its intent to retire the Pirkey Plant in 2023. SWEPCO expects deliveries from Sabine to continue until the first quarter of 2023 at which time Sabine expects to begin final reclamation. Funding for mine reclamation is the responsibility of SWEPCO.

During 2020, Caddo Creek Resources Company, LLC (“Caddo Creek”) ceased all mining and delivery of lignite and commenced mine reclamation. Funding for mine reclamation is the responsibility of a subsidiary of Advanced Emissions Solutions (“AES”). Caddo Creek entered into a contract with a subsidiary of AES to perform the required mine reclamation. The reclamation at Caddo Creek is expected to be substantially complete during the first half of 2022.

During 2020, the contract mining agreement between Camino Real Fuels, LLC (“Camino Real”) and its customer, Dos Republicas Coal Partnership (“DRCP”), terminated and resulted in mine closure. Funding for mine reclamation is the responsibility of DRCP.

NAMining Segment

In the third quarter of 2021, NAMining entered into contracts with a new customer to perform all mining operations at two sand and gravel quarries located in Texas and Arkansas. The initial term of each contract is two years, and one of the contracts automatically extends an additional two years provided NAMining is not in default under that contract. In the second quarter of 2021, NAMining entered into a one-year mining services contract with an existing customer for a sand and gravel quarry in Indiana. In the first quarter of 2021, NAMining entered into a 15-year mining services contract with a new customer at a limestone quarry in Central Florida. NAMining will operate two smaller draglines at this quarry while it relocates and commissions a larger dragline that will increase production capacity. The relocated dragline is anticipated to be commissioned in the second half of 2022. During 2021, NAMining also amended a contract with a current customer to provide additional services at a limestone quarry in Florida.

In addition, NAMining will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

Thacker Pass is owned by Lithium Nevada Corp., a subsidiary of Lithium Americas Corp. (TSX: LAC) (NYSE: LAC). Lithium Americas Corp. owns the lithium reserves at Thacker Pass and will be responsible for the processing and sale of the lithium

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produced. At maturity, the Thacker Pass management fee contract is expected to deliver fee income similar to a mid-sized management fee coal mine.

Minerals Management Segment

During 2021 and 2020, the Minerals Management segment acquired additional mineral interests, primarily in the Eagle Ford and Permian Basins in Texas. During the second quarter of 2021, the Minerals Management segment, through its Catapult business, acquired a combination of mineral and overriding royalty interests in the Eagle Ford Basin, which includes approximately 14.1 thousand gross acres and 1.7 thousand net royalty acres, for an initial payment of $4.7 million. Under the terms of the transaction, Catapult could make additional payments for each additional well developed on the acquired assets during 2022 of up to a maximum of $0.6 million. Catapult also completed a small acquisition of royalty interests in the Delaware Basin during 2021 for a purchase price of $0.3 million. Minerals Management intends to continue to make future acquisitions of mineral and royalty interests that meet the Company’s acquisition criteria as part of its growth strategy.

Operations

Coal Mining Segment

The Coal Mining segment, NACoal, operates surface coal mines under long-term contracts with power generation companies and an activated carbon producer pursuant to a service-based business model. Coal is surface mined in North Dakota, Texas, Mississippi and Louisiana. Through September 30, 2021, the Company provided contract mining services on the Navajo Nation in New Mexico. Each mine is fully integrated with its customer's operations.

During 2021, the Company's operating coal mines were: Bisti, Coteau, Coyote Creek Mining Company, LLC (“Coyote Creek”), Demery Resources Company, LLC (“Demery”), Falkirk, Mississippi Lignite Mining Company (“MLMC”) and Sabine.

Coteau, Coyote, Falkirk, MLMC and Sabine supply lignite coal for power generation. Demery supplies lignite coal for the production of activated carbon products. Each mine is the exclusive supplier of coal to its customers' facilities. Each of these mines delivers its coal production to adjacent or nearby power plants, synfuels plants or an activated carbon processing facility under long-term supply contracts. MLMC’s lignite sales agreement contains a minimum annual take provision; all other coal supply contracts are requirements contracts under which earnings can fluctuate based on customer requirements. Certain coal supply contracts can be terminated early, which would result in a reduction to future earnings.

At all operating coal mines other than MLMC, the Company is paid a management fee per ton of coal or heating unit (MMBtu) delivered. Each contract specifies the indices and mechanics by which fees change over time, generally in line with broad measures of U.S. inflation. The customers are responsible for funding all mine operating costs, including final mine reclamation, and directly or indirectly provide all of the capital required to build and operate the mine. This contract structure eliminates the Company's exposure to spot coal market price fluctuations while providing income and cash flow with minimal capital investment. Other than at Coyote Creek, debt financing provided by or supported by the customers is without recourse to NACCO and NACoal. See Note 17 to the Consolidated Financial Statements in this Form 10-K for further discussion of Coyote Creek's guarantees.

All operating coal mines other than MLMC meet the definition of a variable interest entity (“VIE”). In each case, NACCO is not the primary beneficiary of the VIE as it does not exercise financial control; therefore, NACCO does not consolidate the results of these operations within its financial statements. Instead, these contracts are accounted for as equity method investments. The income before income taxes associated with these VIEs is reported as Earnings of unconsolidated operations on the Consolidated Statements of Operations, and the Company’s investment is reported on the line Investments in unconsolidated subsidiaries in the Consolidated Balance Sheets. The mines that meet the definition of a VIE are referred to collectively as the “Unconsolidated Subsidiaries.” For tax purposes, the Unconsolidated Subsidiaries are included within the NACCO consolidated U.S. tax return; therefore, the income tax expense line on the Consolidated Statements of Operations includes income taxes related to these entities. See Note 17 to the Consolidated Financial Statements in this Form 10-K for further information on the Unconsolidated Subsidiaries.

The Company performs contemporaneous reclamation activities at each mine in the normal course of operations. Under all of the Unconsolidated Subsidiaries’ contracts, the customer has the obligation to fund final mine reclamation activities. Under certain contracts, the Unconsolidated Subsidiary holds the mine permit and is therefore responsible for final mine reclamation activities. To the extent the Unconsolidated Subsidiary performs such final reclamation, it is compensated for providing those services in addition to receiving reimbursement from customers for costs incurred.

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Caddo Creek met the definition of a VIE prior to the cessation of mining on September 30, 2020. The terms of the contract to perform mine reclamation contain a fixed-price component and therefore, Caddo Creek has been consolidated within the Company's financial statements since October 1, 2020.

The MLMC contract is the only operating coal contract in which the Company is responsible for all operating costs, capital requirements and final mine reclamation; therefore, MLMC is consolidated within NACCO’s financial statements. MLMC sells coal to its customer at a contractually agreed-upon price which adjusts monthly, primarily based on changes in the level of established indices which reflect general U.S. inflation rates. Profitability at MLMC is affected by customer demand for coal and changes in the indices that determine sales price and actual costs incurred. As diesel fuel is heavily weighted among the indices used to determine the coal sales price, fluctuations in diesel fuel prices can result in significant fluctuations in earnings at MLMC.

MLMC delivers coal to the Red Hills Power Plant in Ackerman, Mississippi. The Red Hills Power Plant supplies electricity to the Tennessee Valley Authority ("TVA") under a long-term Power Purchase Agreement ("PPA"). MLMC’s contract with its customer runs through 2032. TVA’s power portfolio includes coal, nuclear, hydroelectric, natural gas and renewables. The decision of which power plants to dispatch is determined by TVA. Reduction in dispatch of the Red Hills Power Plant will result in reduced coal deliveries and earnings at MLMC.

See “Item 2. Properties" on page 31 in this Form 10-K for discussion of the Company's mineral resources and mineral reserves.

NAMining Segment

The NAMining segment provides value-added contract mining and other services for producers of aggregates, lithium and other minerals. The segment is a primary platform for the Company’s growth and diversification of mining activities outside of the coal industry. NAMining provides contract mining services for independently owned mines and quarries, creating value for its customers by performing the mining aspects of its customers’ operations. This allows customers to focus on their areas of expertise: materials handling and processing, product sales and distribution. NAMining historically operated primarily at limestone quarries in Florida, but is focused on expanding outside of Florida, mining materials other than limestone and expanding the scope of mining operations provided to its customers. As of December 31, 2021, NAMining operates mines in Florida, Texas, Arkansas and Indiana and will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

NAMining utilizes both fixed price and management fee contract structures. Certain of the entities within the NAMining segment are VIEs and are accounted for under the equity method as Unconsolidated Subsidiaries. See Note 17 to the Consolidated Financial Statements in this Form 10-K for further information on the Unconsolidated Subsidiaries.

Minerals Management Segment

The acquisition criteria for building a blended portfolio of mineral and royalty interests includes (i) new wells anticipated to come online within one to two years of investment, (ii) areas with forecasted future development within five years after acquisition, or (iii) existing producing wells further along the decline curve that will generate stable cash flow. In addition, acquisitions should extend the geographic footprint to diversify across multiple basins with a preliminary focus on the more oil-rich Permian basin and a secondary focus on other diversifying basins to increase regional exposure. While the current focus is on the acquisition of mineral and royalty interests, the Company would also consider investments in overriding royalty interests, non-participating royalty interests or non-operated working interests under certain circumstances. The current acquisition strategy does not contemplate any near-term working interest investments in which the Company would act as the operator.

Total consideration for the 2021 and 2020 acquisitions of mineral and royalty interests was $5.3 million and $14.2 million, respectively. The 2021 acquisitions include 20.6 thousand gross acres and 1.8 thousand net royalty acres. The 2020 acquisitions include 65.5 thousand gross acres and 1.2 thousand net royalty acres. Total mineral and royalty interests include approximately 127.8 thousand gross acres and 59.9 thousand net royalty acres at December 31, 2021.

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Mississippi (coal), Pennsylvania (coal, coalbed methane and Marcellus shale natural gas), Alabama (coal, coalbed methane and natural gas) and North Dakota (coal, oil and natural gas). The majority of the Company’s legacy reserves were acquired as part of its historical coal mining operations.

The Minerals Management segment owns royalty interests, mineral interests, nonparticipating royalty interests, and overriding royalty interests.

•Royalty Interest. Royalty interests generally result when the owner of a mineral interest leases the underlying minerals to an exploration and production company pursuant to an oil and gas lease. Typically, the resulting royalty interest is a cost-free percentage of production revenues for minerals extracted from the acreage. A holder of royalty interests is generally not responsible for capital expenditures or lease operating expenses, but may be responsible for certain post-production expenses, and typically have no environmental liability. Royalty interests expire upon the expiration of the oil and gas lease.

•Mineral Interest. Mineral interests are perpetual rights of the owner to explore, develop, exploit, mine, and/or produce any or all of the minerals lying below the surface of the property. The holder of a mineral interest has the right to lease the minerals to an exploration and production company. Upon the execution of an oil and gas lease, the lessee (the exploration and production company) becomes the working interest owner and the lessor (the mineral interest owner) has a royalty interest.

•Non-Participating Royalty Interest (“NPRIs”). NPRI is an interest in oil and gas production which is created from the mineral estate. The NPRI is expense-free, bearing no operational costs of production. The term “non-participating” indicates that the interest owner does not share in the bonus, rentals from a lease, nor the right to participate in the execution of oil and gas leases.

•Overriding Royalty Interest (“ORRIs”). ORRIs are created by carving out the right to receive royalties from a working interest. Like royalty interests, ORRIs do not confer an obligation to make capital expenditures or pay for lease operating expenses and have limited environmental liability, however ORRIs may be calculated net of post-production expenses, depending on how the ORRI is structured. ORRIs that are carved out of working interests are linked to the same underlying oil and gas lease that created the working interest, and therefore, such ORRIs are typically subject to expiration upon the expiration or termination of the oil and gas lease.

The Company may own more than one type of mineral and royalty interest in the same tract of land. For example, where the Company owns an ORRI in a lease on the same tract of land in which it owns a mineral interest, the ORRI in that tract will relate to the same gross acres as the mineral interest in that tract.

The Minerals Management segment will benefit from the continued development of its mineral properties without the need for investment of additional capital once mineral and royalty interests have been acquired. The Minerals Management segment does not have any investments under which it would be required to bear the cost of exploration, production or development.

See “Item 2. Properties" on page 31 in this Form 10-K for discussion of the Company's proved reserves.

Customers

The principal customers of the Coal Mining segment are electric utilities, an independent power provider and a producer of activated carbon.

The principal customers of the NAMining segment are limestone producers and to a lesser extent, sand and gravel producers. In addition, NAMining will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

The Minerals Management segment generates income primarily from royalty-based lease payments from oil, gas and to a lesser extent, coal producers. The pricing of oil, gas and coal sales is primarily determined by supply and demand in the marketplace and can fluctuate considerably. As a royalty owner and non-operator, the Company has limited access to timely information, involvement, and operational control over the volumes of oil, gas and coal produced and sold and the terms and conditions on which such volumes are marketed and sold.

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In 2021 and 2020, two customers individually accounted for more than 10% of consolidated revenues. The following represents the revenue attributable to each of these entities as a percentage of consolidated revenues for those years:


	Percentage of Consolidated Revenues
Segment	2021		2020
Coal Mining customer	43	%	55	%
NAMining customer	19	%	19	%

The loss of either of these customers could have a material adverse effect on the results of operations attributable to the applicable segment and on the Company's consolidated results of operations.

In addition to the customers listed above, the Company has certain subsidiaries that meet the definition of a VIE; therefore, NACCO does not consolidate the results of these operations within its financial statements. Instead, these contracts are accounted for as equity method investments. For the year ended December 31, 2021, the Coal Mining segment derived approximately 68% of the Earnings of Unconsolidated Operations from two customers, Basin Electric and GRE. The loss of either of these contracts could have a material adverse effect on the Earnings of Unconsolidated Operations of the Coal Mining segment and a material adverse effect on the Company's Consolidated Statements of Operations.

Competition

The Company's coal mines are directly adjacent to the customer’s property, with economical delivery methods that include conveyor belt delivery systems linked to the customer’s facilities or short-haul rail systems. All of the mines in the Coal Mining segment are the most economical suppliers to each of their respective customers as a result of transportation advantages over competitors. In addition, the customers' facilities were specifically designed to use the coal being mined.

The coal industry competes with other sources of energy, particularly oil, gas, hydro-electric power and nuclear power. In addition, it competes with subsidized sources of energy, primarily wind and solar. Among the factors that affect competition are the price and availability of oil and natural gas, environmental and related political considerations, the time and expenditures required to develop new energy sources, the cost of transportation, the cost of compliance with governmental regulations, the impact of federal and state energy policies, the impact of subsidies on renewable pricing and the Company's customers' dispatch decisions, which may also take into account carbon dioxide emissions. The ability of the Coal Mining segment to maintain comparable levels of coal production at existing facilities and to market and develop its reserves will depend upon the interaction of these factors.

Electricity generating units are chosen to run primarily based on operating costs, of which fuel costs account for the largest share. Natural gas-fired power plants have the most potential to continue to displace coal-fired electric baseload power generation in the near term. There also continues to be an increase in the amount of electricity generated by wind and solar. Fluctuations in natural gas prices and the availability of renewable generation, particularly wind, can contribute to changes in power plant dispatch and customer demand for coal. The significant increase in natural gas prices in 2021 compared to natural gas prices in 2020 contributed to an increase in customer power plant dispatch and coal deliveries in 2021. Sustained higher natural gas prices could lead to increased demand for coal and positively affect Coal Mining segment results. Over the longer term, the Company continues to believe that customer demand will remain pressured by continuing increases in subsidized renewable generation sources, particularly wind. Federal and state mandates for increased use of electricity derived from renewable energy sources have also negatively affected demand for coal. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, make alternative fuel sources competitive with coal. The Taxpayer Certainty and Disaster Tax Relief Act of 2020 extended the production tax credit (“PTC”) under Section 45 of the Internal Revenue Code and the investment tax credit (“ITC”) under Section 48 of the Code. The PTC for wind was extended at the current phase-out level (60% of the otherwise allowable credits) for facilities where construction began in 2021. The ITC for solar was extended at 26% for energy property where construction begins in 2021-2022 and at 22% where construction begins in 2023-2025. Solar energy property placed in service after December 31, 2025 will receive a 10% ITC. Environmental, social and governance considerations can also have an impact on power plant dispatch and demand for coal.

Based on industry information, the Company believes it was one of the ten largest coal producers in the U.S. in 2021 based on total coal tons produced.

NAMining faces competition from producers of aggregates, lithium or other minerals that choose to self-perform mining operations and from other mining companies.

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In the Minerals Management segment, the oil and gas industry is intensely competitive; the Company primarily competes with companies and investors for the acquisition of oil and gas properties, some of which have greater resources and may be able to pay more for productive oil and natural gas properties or to define, evaluate, bid for and purchase a greater number of properties than the Company’s financial resources permit. Additionally, many of the Minerals Management segment's competitors are, or are affiliated with, operators that engage in the exploration and production of their oil and gas properties, which allows them to acquire larger assets that include operated properties. Larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than the Company can, which would adversely affect its competitive position. The integrated competitors may also have a better understanding of when minerals they acquire will be developed, as they are often the developer. The Minerals Management segment’s ability to acquire additional properties in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because the Company has fewer financial resources than many companies in the oil and gas industry, the Company may be at a disadvantage in bidding for oil and natural gas properties.

Seasonality

The Company has experienced limited variability in its results due to the effect of seasonality; however, variations in coal demand can occur as a result of the timing and duration of planned or unplanned outages at customers' facilities. Variations in coal demand can also occur as a result of changes in market prices of competing fuels such as natural gas, wind and solar power and demand for electricity, which can fluctuate based on changes in weather patterns.

The NAMining segment extracts a significant amount of the annual limestone produced in Florida. The Florida construction industry can be affected by the cyclicality of the economy, seasonal weather conditions and pandemics, all of which can result in variations in demand for aggregates.

In the Minerals Management segment, oil and natural gas wells have high initial production rates and follow a natural decline before settling into relatively stable, long-term production. Decline rates can vary due to factors like well depth, well length, geology, formation pressure, and facility design. In addition to the natural production decline curve, royalty income can fluctuate favorably or unfavorably in response to a number of factors outside of the Company's control, including the number of wells being operated by third parties, fluctuations in commodity prices (primarily oil and natural gas), fluctuations in production rates associated with operator decisions, regulatory risks, the Company's lessees' willingness and ability to incur well-development and other operating costs, and changes in the availability and continuing development of infrastructure.

Human Capital

As of December 31, 2021, the Company and its subsidiaries had approximately 1,600 employees, including approximately 1,100 employees at the Company’s unconsolidated mining operations, none of which are represented by a collective bargaining agreement. NACCO believes it has good relations with its employees.

Market-Based Compensation: NACCO believes its employees are critical to its success and invests in its employees by offering a market-based competitive total rewards package that includes a combination of salaries and wages and a benefits package that promotes employee well-being across all aspects of their lives. The Company provides employee wages that are competitive and consistent with employee positions, skill levels, experience, knowledge and geographic location. Benefits offered to employees include:

•Medical, dental and vision benefits for employee, spouse and dependents;

•Flexible spending accounts for both healthcare and dependent care;

•Health savings accounts and health reimbursement accounts, both of which receive a company contribution;

•Paid vacation and holidays;

•Parental leave;

•Short-term and long-term disability benefits;

•Wellness incentives for employees;

•Life and AD&D insurance benefits;

•Charitable donation matches; and

•Employee assistance program.

Employee Development: The Company recognizes that its culture and success is strengthened when employees are respected, motivated and engaged. The Company works to match employees with assignments that capitalize on the skills, talents and potential of each employee. The Company believes in hiring, engaging, developing and promoting people who are fully able to meet the demands of each position, regardless of race, color, religion, gender, sexual orientation, gender identity, national origin, age, veteran status or disability.

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Safety: Employee safety in the workplace is one of the Company’s core values. The Company is committed to strict compliance with applicable laws and regulations regarding workplace safety and provides on-going safety training, education and communication. Hazards in the workplace are actively identified and management tracks incidents so remedial actions can be taken to improve workplace safety. The Company believes communication related to “near misses,” safety incidents and protocols is essential to continuously developing and maintaining best-practices related to safety and enables identification and correction of operational practices that might impair employee safety or health.

Company Ethics: The Company has processes in place for compliance with its Code of Corporate Conduct, Insider Trading Policy and Anti-Corruption Policy. All of the Company's Directors and employees annually complete certifications with respect to compliance with the Company's Code of Corporate Conduct. In addition, all employees of the Company are required to complete annual Code of Corporate Conduct training. Ethics are deeply embedded in the Company’s values and business processes. The Company also maintains an ethics related hotline, managed by a third party, through which individuals can anonymously raise concerns or ask questions about business behavior.

Community Engagement: The Company supports its local communities and is committed to helping them remain safe, healthy and resilient. The Company's past activities include corporate donations, volunteerism and education. Community engagement is encouraged and supported through the Company's matching gift program. The Company will match employee contributions up to $5,000 per employee if program criteria are met.

Available Information

The Company makes its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports available, free of charge, through its website, www.nacco.com, as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”). The content of the Company's website is not incorporated by reference into this Form 10-K or in any other report or document filed with the SEC, and any reference to the Company's website is intended to be an inactive textual reference only.

Under Rule 12b-2 of the Exchange Act, the Company qualifies as a “smaller reporting company” because its public float as of the last business day of the Company’s most recently completed second quarter was less than $250 million. For as long as the Company remains a “smaller reporting company,” it may take advantage of certain exemptions from the SEC’s reporting requirements that are otherwise applicable to public companies that are not smaller reporting companies.

Government Regulation

The Company's operations are subject to various federal, state and local laws and regulations on matters such as employee health and safety, and certain environmental laws and regulations relating to, among other matters, the reclamation and restoration of coal mining properties, air pollution, water pollution, the disposal of wastes and effects on groundwater. In addition, the electric power generation industry is subject to extensive regulation regarding the environmental impact of its power generation activities that could affect demand for coal from the Company's Coal Mining segment. Many aspects of the production, pricing and marketing of oil and natural gas are regulated by federal and state agencies. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, which frequently increases the regulatory burden on affected members of the industry and could affect the results of the Company’s Minerals Management segment.

Numerous governmental permits and approvals are required for coal mining operations. The Company's subsidiaries hold or will hold the necessary permits at all of its coal mining operations except Demery and Caddo Creek, where the customers hold the respective permits. The Company believes, based upon present information provided to it by these third-party mine permit holders, that these third parties have all permits necessary for the Company to operate or reclaim Caddo Creek and Demery; however, the Company cannot be certain that these third parties will be able to maintain all such permits in the future.

At the coal mining operations where the Company's subsidiaries hold the permits, the Company is required to prepare and present to federal, state or local governmental authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment and public and employee health and safety.

Some laws, as discussed below, place many requirements on the coal mining operations and the limestone quarries where the Company provides services. Federal and state regulations require regular monitoring of the Company's operations to ensure compliance.

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Mine Health and Safety Laws

The Federal Mine Safety and Health Act of 1977 imposes safety and health standards on all mining operations. Regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters. The Federal Mine Safety and Health Administration enforces compliance with these federal laws and regulations.

Environmental Laws

The Company's coal mining operations are subject to various federal environmental laws, as amended, including:

•the Surface Mining Control and Reclamation Act of 1977 (“SMCRA”);

•the Clean Air Act, including amendments to that act in 1990 (“CAA”);

•the Clean Water Act of 1972 (“CWA”);

•the Resource Conservation and Recovery Act ("RCRA");

•the National Environmental Policy Act of 1970 (“NEPA”); and

•the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA").

In addition to these federal environmental laws, various states have enacted environmental laws that provide for higher levels of environmental compliance than similar federal laws. These state environmental laws require reporting, permitting and/or approval of many aspects of coal mining operations. Both federal and state inspectors regularly visit mines to enforce compliance. The Company has ongoing training, compliance and permitting programs to ensure compliance with such environmental laws. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect the Coal Mining segment.

Surface Mining Control and Reclamation Act

SMCRA establishes mining, environmental protection and reclamation standards for all aspects of surface coal mining operations. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the primary regulatory authority.

Coal mine operators must obtain SMCRA permits and permit renewals for coal mining operations from the applicable regulatory agency. These SMCRA permit provisions include requirements for coal prospecting, mine plan development, topsoil removal, storage and replacement, selective handling of overburden materials, mine pit backfilling and grading, protection of the hydrologic balance, surface drainage control, mine drainage and mine discharge control and treatment, and revegetation.

Although mining permits have stated expiration dates, SMCRA provides for a right of successive renewal. The cost of obtaining surface mining permits can vary widely depending on the quantity and type of information that must be provided to obtain the permits; however, the cost of obtaining a permit is usually between $1,000,000 and $5,000,000, and the cost of obtaining a permit renewal is usually between $15,000 and $100,000.

The Abandoned Mine Land Fund, which is provided for by SMCRA, imposes a fee on certain coal mining operations. The proceeds are intended to be used principally to reclaim mine lands closed prior to 1977. In addition, the Abandoned Mine Land Fund also makes transfers annually to the United Mine Workers of America Combined Benefit Fund (the “Fund”), which provides health care benefits to retired coal miners who are beneficiaries of the Fund. The 2021 Infrastructure Investment and Jobs Act reauthorized the Abandoned Mine Land fee at a reduced rate. The fee for lignite coal was reduced from $0.08 per ton to $0.064 per ton and for other surface-mined coal from $0.28 per ton to $0.224 per ton. These fees have been reauthorized until the end of fiscal year 2035.

SMCRA establishes operational, reclamation and closure standards for surface coal mines. The Company accrues for the costs of current mine disturbance and final mine closure, including the cost of treating mine water discharges, at mines where the Company's subsidiaries hold the mining permit. These obligations are largely unfunded, with the exception of the final mine closure costs for the Coyote Creek Mine, which are being funded throughout the production stage.

SMCRA stipulates compliance with many other major environmental programs, including the CAA and CWA. The U.S. Army Corps of Engineers regulates activities affecting navigable waters, and the U.S. Bureau of Alcohol, Tobacco and Firearms regulates the use of explosives for blasting. In addition, the U.S. Environmental Protection Agency (the “EPA”), the U.S. Army Corps of Engineers and the OSMRE have engaged in a series of rulemakings and other administrative actions under the CWA and other statutes that are directed at reducing the impact of coal mining operations on water bodies.

The Company does not believe there is any significant risk to the Company's subsidiaries ability to maintain its existing mining permits or its ability to acquire future mining permits for its mines.

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Clean Air Act and Affordable Clean Energy Rule ("ACE")

The process of burning coal can cause many compounds and impurities in the coal to be released into the air, including sulfur dioxide, nitrogen oxides, mercury, particulates and other matter. The CAA and the corresponding state laws that extensively regulate the emissions of materials into the air affect coal mining operations both directly and indirectly. Direct impacts on coal mining operations occur through CAA permitting requirements and/or emission control requirements relating to air contaminants, especially particulate matter. Indirect impacts on coal mining operations occur through regulation of the air emissions of sulfur dioxide, nitrogen oxides, mercury, particulate matter and other compounds emitted by coal-fired power plants. The EPA has promulgated or proposed regulations that impose tighter emission restrictions in a number of areas, some of which are currently subject to litigation. The general effect of tighter restrictions is to reduce demand for coal. Ongoing reduction in coal’s share of the capacity for power generation could have a material adverse effect on the Company’s business, financial condition and results of operations.

States are required to submit to the EPA revisions to their state implementation plans ("SIPs") that demonstrate the manner in which the states will attain national ambient air quality standards ("NAAQS") every time a NAAQS is issued or revised by the EPA. The EPA has adopted NAAQS for several pollutants, which continue to be reviewed periodically for revisions. When the EPA adopts new, more stringent NAAQS for a pollutant, some states have to change their existing SIPs. If a state fails to revise its SIP and obtain EPA approval, the EPA may adopt regulations to effect the revision. Coal mining operations and coal-fired power plants that emit particulate matter or other specified material are, therefore, affected by changes in the SIPs. Through this process over the last few years, the EPA has reduced the NAAQS for particulate matter, ozone, and nitrogen oxides. The Company's coal mining operations and power generation customers may be directly affected when the revisions to the SIPs are made and incorporate new NAAQS for sulfur dioxide, nitrogen oxides, ozone and particulate matter. In March 2019, the EPA published a final rule that retains the current primary (health-based) NAAQS for sulfur oxides (SOx) without revision. The current primary standard is set at a level of 75 parts per billion, as the 99th percentile of daily maximum 1-hour SO2 concentrations, averaged over 3 years. In mid-2011, the EPA finalized the Cross-State Air Pollution Rule ("CSAPR") to address interstate transport of pollutants. This affects states in the eastern half of the U.S. and Texas. This rule imposes additional emission restrictions on coal-fired power plants to attain ozone and fine particulate NAAQS. The EPA began implementation of the rule in 2015, when Phase I emission reductions in sulfur dioxide and nitrogen dioxide became effective. Phase II reductions became effective in 2017. In 2016, the EPA mandated additional reductions in nitrogen oxide emissions. The U.S. Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") remanded the CSAPR Update to the EPA to address the court’s holding that the rule unlawfully allows significant contribution to continue beyond downwind attainment deadlines. In 2018, the EPA finalized all remaining ozone designations to comply with the 2015 ozone air quality standards. The U.S. Court of Appeals for the D.C. Circuit issued a per curium opinion rejecting various industry challenges to the EPA’s 2015 revisions to the ozone NAAQS, including that the EPA was required to consider certain adverse effects and background ozone when setting the standards. None of the power plants supplied by the Company are within non-attainment areas for ozone. In March 2021, EPA finalized the “Revised Cross-State Air Pollution Rule” to address the remand of the CSAPR update. The final rule requires no further obligations in states where the Company’s customers operate a power plant.

The CAA Acid Rain Control Provisions were promulgated as part of the CAA Amendments of 1990 in Title IV of the CAA (“Acid Rain Program”). The Acid Rain Program required reductions of sulfur dioxide emissions from coal-fired power plants. The Acid Rain Program is now a mature program, and the Company believes that any market impacts of the required controls have likely been factored into the coal market.

The EPA promulgated a regional haze program designed to protect and to improve visibility at and around Class I Areas, which are generally National Parks, National Wilderness Areas and International Parks. This program may restrict the construction of new coal-fired power plants, the operation of which may impair visibility at and around the Class I Areas. Additionally, the program requires certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxide and particulate matter. States were required to submit Regional Haze SIPs to the EPA in 2007; however, many states did not meet that deadline. In 2016, the EPA finalized revisions to the Regional Haze Rule which addresses requirements for the second planning period. In September 2019, the EPA issued final regional haze guidance that indicates that a re-evaluation of sources already subject to best available retrofit technologies ("BART") is likely unnecessary. The guidance also encourages states to balance visibility benefits against other factors in selecting the measures necessary to make “reasonable progress” toward natural visibility conditions. Finally, when comparing various control options to determine which ones may be “cost-effective,” the final guidance recommends comparing cost to visibility benefits. In July of 2021, the EPA released a memorandum to clarify the guidance issued in 2019. While this clarification memorandum attempted to reverse some of the core conclusions made in the 2019 guidance, it was released after the air analyses to develop individual SIPs had been completed and just prior to the SIP submittal deadline to the EPA, which was July 31, 2021. Many SIP submittals were delayed due to emissions modeling and continue to be developed and scrutinized. SIPs will be sent to the EPA for approval following both review by federal land managers of the National Park Service, the United States Fish and

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Wildlife Service and the United States Forest Service and all corresponding public comment periods. See "Item 1A - “Risk Factors” on page 20 for further discussion of the regional haze program.

Under the CAA, new and modified sources of air pollution must meet certain new source standards (the “New Source Review Program”). In the late 1990s, the EPA filed lawsuits against owners of many coal-fired power plants in the eastern U.S. alleging that the owners performed non-routine maintenance, causing increased emissions that should have triggered the application of these new source standards. Some of these lawsuits have been settled with the owners agreeing to install additional emission control devices in their coal-fired power plants. The EPA has clarified the process for evaluating whether the New Source Review (“NSR”) permitting program would apply to proposed projects at existing air pollution sources. Under the NSR program, before constructing a new stationary emission source or a modification of an existing major source, the source owner or operator must determine whether the new source will emit or the modification will increase air emissions above certain thresholds. The rule makes it clear that both emissions increases and decreases from a major modification at an existing source are to be considered during Step 1 of the two-step NSR applicability test which is designed to determine if there is a “significant emission increase”. In October 2021, the EPA denied a petition for reconsideration and administrative stay of the final rule; however, the remaining litigation and the uncertainty around the NSR program rules could adversely impact demand for coal. Any additional new controls may have an adverse impact on the demand for coal, which may have a material adverse effect on the Company’s business, financial condition or results of operations.

Under the CAA, the EPA also adopts national emission standards for hazardous air pollutants. In December 2011, the EPA adopted a final rule called the Mercury and Air Toxics Standard (“MATS”), which applies to new and existing coal-fired and oil-fired units. This rule requires mercury emission reductions in fine particulates, which are being regulated as a surrogate for certain metals.

The Company's power generation customers must incur substantial costs to control emissions to meet all of the CAA requirements, including the requirements under MATS and the EPA's regional haze program. These costs raise the price of coal-generated electricity, making coal-fired power less competitive with other sources of electricity, thereby reducing demand for coal. If the Company's customers cannot offset the cost to control certain regulated pollutant emissions by lowering costs or if the Company's customers elect to close coal-fired units, the Company’s business, financial condition and results of operations could be materially adversely affected.

Global climate change continues to attract considerable attention in the United States. The U.S. Congress has considered climate change legislation aimed at reducing greenhouse gas (“GHG”) emissions, particularly from coal combustion by power plants. Enactment of laws and passage of regulations regarding GHG emissions by the U.S. or additional states, or other actions to limit carbon dioxide emissions, such as opposition by environmental groups to expansion or modification of coal-fired power plants, could result in electric generators switching from coal to other fuel sources.

The U.S. Congress continues to consider a variety of proposals to reduce GHG emissions from the combustion of coal and other fuels. These proposals include emission taxes, emission reductions, including carbon tax and “cap-and-trade” programs, and mandates or incentives to generate electricity by using renewable resources, such as wind or solar power. Some states have established programs to reduce GHG emissions. Further, governmental agencies have been providing grants or other financial incentives to entities developing or selling alternative energy sources with lower levels of GHG emissions, which may lead to more competition from those entities.

The EPA introduced a GHG regulation program under the CAA by issuing a finding that the emission of six GHGs, including carbon dioxide and methane, may reasonably be anticipated to endanger public health and welfare. Based on that finding, the EPA published a New Source Performance Standard for greenhouse gases, applicable to certain new power plants. In 2019, the EPA issued the Affordable Clean Energy ("ACE") Rule to reduce GHG emissions from existing electric generating units ("EGUs"). In contrast to the Clean Power Plan, the ACE rule limited "best system of emission reduction" ("BSER") to only "inside the fenceline" heat rate improvement technologies or systems that can be applied at an affected coal-fired EGU. The ACE rule was challenged by a suite of petitioners before the U.S. Circuit Court of Appeals, District of Columbia Circuit ("DC Circuit") which subsequently ruled that the EPA erred when it rescinded the Clean Power Plan and they vacated the ACE rule. In early 2021, the EPA issued an endangerment/significant contribution finding for carbon dioxide emissions from coal-fired power plants. In addition, the DC Circuit court ruling was challenged by several parties, including the Company, and the Supreme Court of the United States recently granted certiorari. The Supreme Court of the United States will hear the case in February 2022. Depending on the outcome of the Supreme Court ruling, the EPA may draft a new rule to regulate carbon dioxide emissions which, depending on the scope and applicability of the rule, may have a material adverse effect on the Company’s business, financial condition or results of operations.

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The U.S. has not implemented the 1992 Framework Convention on Global Climate Change (“Kyoto Protocol”), which became effective for many countries on February 16, 2005. The Kyoto Protocol was intended to limit or reduce emissions of GHGs. The U.S. has not ratified the emission targets of the Kyoto Protocol or any other GHG agreement. Though the U.S. has not accepted these international GHG limiting treaties, numerous lawsuits and regulatory actions have been undertaken by states and environmental groups to try to force controls on the emission of carbon dioxide; or to prevent the construction of new coal-fired power plants.

As a successor to the Kyoto Protocol, in 2015, international negotiators finalized the Paris Agreement under the United Nations Framework Convention on Climate Change (“Paris Agreement”). Unlike the Kyoto Protocol, the Paris Agreement has no binding GHG reduction mandates on signatories. Participating countries only submit a description of their intended GHG reductions, and provide periodic progress updates, with no penalties for not meeting their self-imposed targets. The Paris Agreement also includes language stating that developed countries will provide financial assistance to help developing countries meet their GHG targets and adapt to climate change, but there are no mandated contributions. In November 2020, the United States formally withdrew from the Paris Agreement; however, the United States rejoined in February 2021. The renegotiation and implementation of the Paris Agreement, or other international agreements, the regulations promulgated to date by the EPA with respect to GHG emissions or the adoption of new legislation or regulations to control GHG emissions, could have a materially adverse effect on the Company’s business, financial condition and results of operations.

Significant public opposition has also been raised with respect to the proposed construction of certain new coal-fired EGUs due to the potential for increased air emissions. Such opposition, as well as any corporate or investor policies against coal-fired EGUs or requiring disclosures related to global climate change, could also reduce the demand for the Company's coal or marketability of NACCO stock. Further, policies limiting available financing for the development of new coal-fueled EGUs or coal mines or the retrofitting of existing EGUs could adversely impact the global demand for coal in the future. The potential impact on the Company of future laws, regulations or other policies or circumstances will depend upon the degree to which any such laws, regulations or other policies or circumstances force electricity generators to diminish their reliance on coal as a fuel source. In view of the significant uncertainty surrounding each of these factors, it is not possible for the Company to predict reasonably the impact that any such laws, regulations or other policies may have on the Company's business, financial condition and results of operations. However, such impacts could have a material adverse effect on the Company's business, financial condition and results of operations.

The Company believes it has obtained all necessary permits under the CAA at all of its coal mining operations where it is responsible for permitting and is in compliance with such permits.

Clean Water Act

The Clean Water Act ("CWA") affects coal mining operations by establishing in-stream water quality standards and treatment standards for waste water discharge. Permits requiring regular monitoring, reporting and performance standards govern the discharge of pollutants into water. Waters discharged from coal mines are required to meet these standards. These federal and state requirements could require more costly water treatment and could materially adversely affect the Company’s business, financial condition and results of operations.

The Company believes it has obtained all permits required under the CWA and corresponding state laws and is in compliance with such permits. In many instances, mining operations require securing CWA authorization or a permit from the U.S. Army Corps of Engineers for operations in waters of the United States. The U.S. Army Corps of Engineers and EPA jointly revised the definition of a water of the United States ("WOTUS") in the June 2020 Navigable Water Protection Rule ("NWPR"). The new definition was challenged in court and two court cases resulted in vacatur of the NWPR. In December 2021, the EPA and COE released a draft “Step One” rule to redefine WOTUS by formally rescinding the NWPR and replacing it with a new definition. If the new definition is promulgated as drafted, some of the Company's operations could incur additional costs to mitigate streams and wetlands.

Bellaire is treating mine water drainage from coal refuse piles associated with two former underground coal mines in Ohio and one former underground coal mine in Pennsylvania, and is treating mine water from a former underground coal mine in Pennsylvania. Bellaire anticipates that it will need to continue these activities indefinitely. See Note 7 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's asset retirement obligations.

Bellaire was notified by the Pennsylvania Department of Environmental Protection ("DEP") during 2004 that in order to obtain renewal of a permit, Bellaire would be required to establish a mine water treatment trust (the "Trust"). See Note 7 and Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on the Trust.

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Resource Conservation and Recovery Act

The Resource Conservation and Recovery Act ("RCRA") affects coal mining operations by establishing requirements for the treatment, storage and disposal of wastes, including hazardous wastes. Coal mine wastes, such as overburden and coal cleaning wastes, currently are exempted from hazardous waste management. In December 2014, the EPA finalized a rule specifying management standards for coal combustion residuals or coal ash ("CCRs") as a non-hazardous waste. In 2018, the EPA finalized revisions to the 2014 regulations in response to litigation of the 2014 rule. One revision allows a state director (in a state with an approved CCR permit program) or the EPA (where EPA is the permitting authority) to suspend groundwater monitoring requirements if there is evidence that there is no potential for migration of hazardous constituents to the uppermost aquifer during the active life of the unit and post closure care. The second revision allows issuance of technical certifications in lieu of a professional engineer. In addition, the EPA revised the groundwater protection standards and extended the deadline for some facilities that must close CCR units. In 2020, the EPA finalized additional changes to the CCR rule that classified all clay-lined surface impoundments that receive CCR as unlined, which triggered a pond closure date of April 2021 for impoundments that failed the aquifer location restriction. The EPA also established alternative deadlines to cease receipt of waste to include new site-specific alternatives due to lack of capacity with a deadline to initiate closure no later than October 15, 2023 and a new site-specific alternative due to permanent cessation of coal-fired boilers with two deadlines to complete closure: (a) no later than October 17, 2023 for surface impoundments 40 acres or smaller; and (b) October 17, 2028 for surface impoundments larger than 40 acres. This new rule may raise the cost for CCR disposal at coal-fired power plants, making them less competitive, and/or result in early closure which could have an adverse impact on demand for coal.

The EPA rule exempts CCRs beneficially used at mine sites and reserves any regulation thereof to the OSMRE. The OSMRE suspended all rulemaking actions on CCRs, but could re-initiate them in the future. The outcome of these rulemakings, and any subsequent actions by EPA and OSMRE, could impact those Company operations that beneficially use CCRs. If the Company were unable to beneficially use CCRs, its revenues for handling CCRs from its customers may decrease and its costs may increase due to the purchase of alternative materials for beneficial uses.

National Environmental Policy Act

NEPA requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement. There are certain actions associated with surface coal mining that may trigger these types of assessments by federal agencies. When a NEPA action is required, the Company provides the required information to the appropriate federal agency so that they may complete the environmental assessment. Historically, this process has been lengthy and may take several years to complete. In July 2020, the White House Council on Environmental Quality ("CEQ") issued a final rule updating the original NEPA regulations; however, it was immediately challenged by states and non-governmental organizations. In October 2021, the CEQ issued a new draft rule rescinding many of the revisions from 2020 update. If finalized as drafted, the revised NEPA regulations could adversely affect the Company’s ability to secure necessary permits.

Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases the cost of doing business, these burdens generally do not affect the Company any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas and the sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. The Company cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the Minerals Management segment. Sales of crude oil, condensate and natural gas liquids ("NGLs") are not currently regulated and are made at market prices.

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Environmental Matters

Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on the Company’s mineral interests, which could materially adversely affect the Minerals Management segment. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations. The strict, joint and several liability nature of such laws and regulations could impose liability upon the operators on the Company’s mineral interests, regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect the Minerals Management segment.

Drilling and Production

The operations of the Company’s third-party lessees are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The states, and some counties and municipalities, in which the Company has mineral interests also regulate one or more of the following:

•the location of wells;

•the method of drilling and casing wells;

•the timing of construction or drilling activities, including seasonal wildlife closures;

•the rates of production or "allowables";

•the surface use and restoration of properties upon which wells are drilled;

•the plugging and abandoning of wells; and

•notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce the Company’s interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas that the lessees of the Company’s mineral interests can produce from existing wells or limit the number of wells or the locations at which operators can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but the effect of any future regulations could have a material effect on the Minerals Management segment. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from the Company’s mineral interests, negatively affect the economics of production from these wells or to limit the number of locations operators can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the operators of the acreage underlying the Company's mineral and royalty interests operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The CWA regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions.

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However, in recent years efforts have been made to regulate hydraulic fracturing at the federal level. In addition, the Biden administration has signaled the intent to stop hydraulic fracturing on federal land.

In addition, several states, including Texas, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature previously adopted legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission subsequently adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit. This law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the Occupational Safety and Health Act for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Further, in May 2013, the Texas Railroad Commission issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting requirements, such as: (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later; and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative or regulatory changes could cause operators of the operation on the acreage underlying the Company’s mineral interests to incur substantial compliance costs, and compliance or the consequences of any failure to comply by operators could have a material adverse effect on the Minerals Management segment.

In addition, hydraulic fracturing operations require the use of a significant amount of water, and the inability of the operators of the acreage underlying the Company’s mineral interests to locate sufficient amounts of water or dispose of or recycle water used in their drilling and production operations, could adversely impact their operations. Moreover, new environmental initiatives and regulations could include restrictions on the ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the development or production of natural gas.

In some instances, the operation of underground injection wells has been alleged to cause earthquakes. Such issues have sometimes led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity. Such concerns also have resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. Future orders or regulations addressing concerns about seismic activity from well injection could affect operations on the acreage underlying the Company’s mineral interests.

Endangered Species Act

The Endangered Species Act (“ESA”) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Pursuant to a settlement with environmental groups, the U.S. Fish and Wildlife Service (“USFWS”) was required to determine whether over 250 species required listing as threatened or endangered under the ESA. USFWS has not yet completed its review, but the potential remains for new species to be listed under the ESA. Some of the Company’s properties or mineral interests may be located in areas that are or may be designated as habitats for endangered or threatened species, and previously unprotected species may later be designated as threatened or endangered in areas where the Company holds interests. For example, recently, there have been renewed calls to review protections currently in place for the Dunes Sagebrush Lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA. Likewise, there have been calls to review protections in place for the Greater Sage Grouse, which can be found across a large swath of the northwestern United States in oil and gas producing states. The listing of either of these species, or any others, in areas where the Company holds minerals interests could cause lessees to incur increased costs arising from species protection

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measures, delay the completion of exploration and production activities, and/or result in limitations on operating activities that could have an adverse impact the Minerals Management segment.

Natural Gas Sales and Transportation

Historically, federal legislation and regulatory controls have affected the price and marketing of natural gas. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.” Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which operators may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that operators produce, as well as the revenues operators receive for sales of natural gas and release of natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, the Company cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can the Company determine what effect, if any, future regulatory changes might have on natural gas-related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in-state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase operators’ costs of transporting gas to point-of-sale locations.

Oil Sales and Transportation

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, the Company believes that the regulation of oil transportation rates will not affect its operations in any materially different way than such regulation will affect the operations of competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by portioning provisions set forth in the pipelines’ published tariffs. Accordingly, the Company believes that access to oil pipeline transportation services generally will be available to its operators to the same extent as to the Company or its competitors.

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State Regulation

Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on the market value of oil production and a 7.5% severance tax on the market value of natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowable from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but the Company cannot be certain that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from wells drilled by third-party lessee's and to limit the number of wells or locations the Company's third-party lessee operators can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. The Company does not believe that compliance with these laws will have a material adverse effect on its results of operations or financial condition.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") and similar state laws create liabilities for the investigation and remediation of releases of hazardous substances into the environment and for damages to natural resources. The Company must also comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.

From time to time, the Company has been the subject of administrative proceedings, litigation and investigations relating to environmental matters.

The extent of the liability and the cost of complying with environmental laws cannot be predicted with certainty due to many factors, including the lack of specific information available with respect to many sites, the potential for new or changed laws and regulations, the development of new remediation technologies and the uncertainty regarding the timing of work with respect to particular sites. As a result, the Company may incur material liabilities or costs related to environmental matters in the future, and such environmental liabilities or costs could materially and adversely affect the Company’s results of operations and financial condition. In addition, there can be no assurance that changes in laws or regulations would not affect the manner in which the Company is required to conduct its operations.

INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The following tables set forth as of March 1, 2022 the name, age, current position and principal occupation and employment during the past five years of the Company’s executive officers. There exists no arrangement or understanding between any executive officer and any other person pursuant to which such executive officer was selected.

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EXECUTIVE OFFICERS OF THE COMPANY

Name

Age

Current Position

Other Positions

J.C. Butler, Jr.

President and Chief Executive Officer of NACCO (from September 2017) and President and Chief Executive Officer of NACoal (from prior to 2017)

From prior to 2017 to September 2017, Senior Vice President - Finance, Treasurer and Chief Administrative Officer of NACCO. From prior to 2017 to September 2017, Assistant Secretary of Hamilton Beach Brands ("HBB") and Kitchen Collection ("KC").

Matthew J. Dilluvio

Associate Counsel and Assistant Secretary of NACCO and NACoal (from June 2019)

From prior to 2017 to May 2019, Associate, Sidley Austin LLP (law firm).

Elizabeth I. Loveman

Vice President and Controller and Principal Financial Officer (from prior to 2017)

John D. Neumann

Vice President, General Counsel and Secretary of NACCO, Vice President, General Counsel and Secretary of NACoal (from prior to 2017)

From prior to 2017 to September 2017, Assistant Secretary of HBB and KC.

Miles B. Haberer

Associate General Counsel of NACCO (from prior to 2017), Associate General Counsel, Assistant Secretary of NACoal (from prior to 2017) and President, North American Coal Royalty Company (an NACoal subsidiary) (from prior to 2017)

Sarah E. Fry

Associate General Counsel and Assistant Secretary of NACCO (from May 2017), Associate General Counsel and Assistant Secretary of NACoal (from May 2017)

From prior to 2017 to April 2017, Senior Counsel, Locke Lord (law firm).

Thomas A. Maxwell

Vice President - Financial Planning and Analysis and
Treasurer (from September 2017)

From prior to 2017 to September 2017, Director of Financial Planning and Analysis and Assistant Treasurer.

PRINCIPAL OFFICERS OF THE COMPANY’S SUBSIDIARIES

Name

Age

Current Position

Other Positions

Eric S. Anderson

President - Mitigation Resources (from March 2017)

From prior to 2017 to February 2017, Environmental Manager, The Sabine Mining Company (an NACoal subsidiary).

Philip N. Berry

President - NAMining (from prior to 2017)

Eric A. Dale

Treasurer and Senior Director, Financial Planning and Analysis, of NACoal (from January 2017)

Carroll L. Dewing

Vice President - Operations of NACoal (from January 2017)

Andrew B. Hart

Controller of NACoal (from September 2019)

From November 2017 to August 2019, Assistant Controller of NACoal. From prior to 2017 to October 2017, Assistant Controller at Rowan Companies, plc.

Brian M. Larson

President - Catapult Mineral Partners, LLC (from May 2019) and Director - Oil and Gas Development (from April 2019)

From prior to 2017 to March 2019, Engineer at Pioneer Natural Resources.

J. Patrick Sullivan, Jr.

Vice President and Chief Financial Officer of NACoal (from prior to 2017)

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Item 1A. RISK FACTORS

The Company operates in a rapidly changing environment that involves a number of risks. The following discussion highlights some of these risks and others are discussed elsewhere in this report. These and other risks could materially and adversely affect the Company’s business, financial condition, operating results or cash flows. The following risk factors are not an exhaustive list of the risks associated with the Company’s business. New factors may emerge or changes to these risks could occur that could materially affect the Company’s business.

Risks related to the Coal Mining segment

Termination of or default under long-term mining contracts could adversely affect the Company's business, financial condition, results of operation and cash flows.

Substantially all of the Coal Mining segment's profits are derived from long-term mining contracts. Although the Company has long-term contracts, numerous regulatory authorities, along with well-funded political and environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation. Any customer's premature facility closure, including as discussed in “Item 1. Business — Business Developments" on page 2 or a result of GRE’s failure to complete the sale of Coal Creek Station and the adjacent high-voltage direct current transmission line to Rainbow Energy and its affiliates currently anticipated to close in the second quarter of 2022, could have a material adverse effect on the Company’s business, financial condition and results of operations.

State implementation of the EPA’s Regional Haze Rule (“RHR”) could require Coyote Creek’s customers to incur significant new costs at the Coyote Station power plant, which could, dependent on determinations by state regulatory commissions regarding approval to recover such costs from the customers of Coyote Creek’s customer, negatively impact Coyote Creek’s customers’ net income, financial position and cash flows. The Company understands that the North Dakota Department of Environmental Quality (“NDDEQ”) could require sources subject to RHR Round 2 reasonable progress determinations, including Coyote Station, to undertake emissions control measures. The emissions modeling conducted for the combined western state agencies affected by the RHR was delayed and has subsequently delayed the NDDEQ state implementation plan process. Therefore, the NDDEQ's state implementation plan, which was due to the EPA by July 2021, is anticipated to be submitted to EPA early in 2022. If NDDEQ requires significant emissions controls at Coyote Station power plant by December 31, 2028, it may not be economically feasible for Coyote Creek's customers to invest in such equipment and an early retirement of Coyote Station and the Coyote Creek mine could be necessary.

The Company could be negatively impacted by the decisions of Coyote Creek's customers. In September 2021, one of Coyote Creek's customers, Otter Tail Power Company, filed its 2022 Integrated Resource Plan in Minnesota and North Dakota which included its intent to start the process of withdrawal from its 35 percent ownership interest in Coyote Station power plant with an anticipated exit from the plant by December 31, 2028.

Under certain circumstances of default or termination of Coyote Creek’s Lignite Sales Agreement (“LSA”), the Company would be obligated for payment of a "make-whole" amount to Coyote Creek’s third-party lenders. The “make-whole” amount is based on the excess, if any, of the discounted value of the remaining scheduled debt payments over the principal amount. In addition, in the event Coyote Creek’s LSA is terminated on or after January 1, 2024 by Coyote Creek’s customers, the Company is obligated to purchase Coyote Creek’s dragline and rolling stock for the then net book value of those assets. Any decision by Coyote Creek’s customers to reduce operations or prematurely close the Coyote Creek mine would have a material adverse effect on the Company’s results of operations, financial position and cash flows.

The loss of, or significant reduction in, purchases by NACCO's coal customers could adversely affect the Company's business, financial condition, results of operation and cash flows.

For the year ended December 31, 2021, the Coal Mining segment derived approximately 68% of earnings of unconsolidated operations from two customers, Basin Electric and GRE. There are inherent risks whenever a significant percentage of total earnings are concentrated with a limited number of customers. Earnings from the Coal Mining segment's customers may fluctuate from time to time based on numerous factors, including market conditions and the realignment of customers' power generation portfolios that reduce the electric power generated from coal, which may be outside of the Company's control. If any of the Coal Mining segment's customers experience declining demand due to market, economic, regulatory or competitive conditions, it could have an adverse effect on the Company's profitability, cash flows and financial position. In addition, if any customers were to significantly reduce or eliminate their purchases of coal from us or if the Company is unable to renew expiring long-term sales agreements with existing customers or enter into new supply agreements, the Company's business, financial condition, results of operations and cash flows could be adversely affected. See “Item 1. Business — Business

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Developments" on page 2 in this Form 10-K for further discussion.

MLMC is subject to risks associated with its capital investment, operating and equipment costs, growing use of alternative generation that competes with coal fired generation, changes in customer demand and inflationary adjustments.

The profitability of MLMC is subject to the risk of loss of investment in this operation, increases in the cost of mining, changes in customer demand, growing competition from alternative power generation that competes with coal-fired generation and the emergence of adverse mining conditions. At MLMC, the costs of mining operations are not reimbursed by MLMC's customer. As such, increased costs at MLMC or decreased revenues could materially reduce the Company's profitability. Any reduction in customer demand at MLMC, including reductions related to reduced mechanical availability of the customer’s power plant, would adversely affect the Company's operating results and could result in significant impairments. MLMC has approximately $136 million of long-lived assets, including property, plant and equipment and a coal supply agreement intangible asset, which are subject to periodic impairment analysis and review. Identifying and assessing whether impairment indicators exist, or if events or changes in circumstances have occurred, including assumptions about future power plant dispatch levels, changes in operating costs and other factors that impact anticipated revenue and customer demand, requires significant judgment. Actual future operating results could differ significantly from these estimates, which may result in an impairment charge in a future period, which could have a substantial impact on the Company’s results of operations.

MLMC sells lignite at contractually agreed upon prices which are subject to changes in the level of established indices over time. As diesel fuel is heavily weighted among the indices used to determine the coal sales price, fluctuations in diesel fuel prices can result in significant fluctuations in earnings at MLMC.

MLMC delivers coal to the Red Hills Power Plant in Ackerman, Mississippi. The Red Hills Power Plant supplies electricity to TVA under a long-term PPA. MLMC’s contract with its customer runs through 2032. TVA’s power portfolio includes coal, nuclear, hydroelectric, natural gas and renewables. In 2019, TVA published its updated Integrated Resource Plan, which indicates plans to increase its reliance on solar power. A decrease in the number of days TVA dispatches the Red Hills Power Plant would reduce MLMC's customer's demand for coal. The decision of which power plants to dispatch is determined by TVA.

Choctaw Generation Limited Partnership ("CGLP") leases the Red Hills Power Plant from a Southern Company subsidiary pursuant to a leveraged lease arrangement. CGLP's ability to make required payments to the Southern Company subsidiary is dependent on the operational performance of the Red Hills Power Plant. During 2020, Southern Company revised the estimated cash flows to be received under the leveraged lease which resulted in a full impairment of the lease investment. If any future lease payment is not paid in full, the Southern Company subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the Red Hills Power Plant. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the Red Hills Power Plant from the Southern Company subsidiary. A foreclosure of the Red Hills Power Plant could have a material adverse effect on MLMC's financial condition, results of operations and cash flows. Southern Company publicly disclosed that all required lease payments have been paid in full through December 31, 2021

Similar to the Company's unconsolidated mines, all production costs at MLMC are capitalized into inventory and recognized in cost of sales as tons are delivered. In periods of limited or no deliveries, MLMC may be required to reduce its inventory carrying value using the lower of cost and net realizable value approach, which could adversely affect MLMC’s results of operations.

Changes in customer demand for any reason, including, but not limited to, reduced mechanical availability of the customer’s power plant, dispatch of power generated by other energy sources ahead of coal, fluctuations in demand due to unanticipated weather conditions, regulations or comparable policies which may promote planned and unplanned outages at the Red Hills Power Plant, economic conditions, including an economic slowdown and a corresponding decline in the use of electricity, governmental regulations and inflationary adjustments could have a material adverse effect on MLMC's financial condition, results of operations and cash flows.

The Coal Mining segment's Unconsolidated Subsidiaries are subject to risks created by changes in customer demand and inflationary adjustments.

The contracts with the Unconsolidated Subsidiaries' customers are primarily based on a "management fee" approach, whereby compensation includes reimbursement of all operating costs, plus a fee based on the amount of coal delivered. The fees earned adjust over time in line with various indices which reflect general U.S. inflation rates. During the production stage, the

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Unconsolidated Subsidiaries' customers pay the Company its agreed upon fee only for the coal delivered to them for consumption or use. As a result, reduced coal usage by customers for any reason, including, but not limited to, fluctuations in demand due to unanticipated weather conditions, scheduled and unscheduled outages at the Coal Mining segment's customers' facilities, unplanned equipment failures, economic conditions or governmental regulations or comparable policies which may promote dispatch of power generated by renewables, such as wind or solar, and the realignment of customers' power generation portfolios that reduce the electric power generated from coal could have a material adverse effect on the Company's results of operations. Because of the contractual price formulas for the management fees at these Unconsolidated Subsidiaries, the profitability of these operations is also subject to fluctuations in inflationary adjustments (or lack thereof) that can impact the agreed upon management fees. These factors could materially reduce the Company's profitability.

Changes in coal consumption patterns of U.S. electric power generators could adversely affect the Company's profitability.

The amount of coal consumed by the electric power generation industry is affected by general economic conditions; overall demand for electricity; availability of transmission; competition from alternative fuel sources for power generation, such as natural gas, nuclear, hydroelectric, wind and solar power, and the location, availability, quality and price of those alternative fuel sources; environmental and other governmental regulations, including those impacting coal-fired power plants; and energy conservation efforts and related governmental policies.

Changes in the utility industry that affect NACCO's customers could also adversely affect the Company. The increased availability of renewable energy sources has contributed to a reduction in demand for coal-fired electric power generation. Competition from natural gas-fired plants that are relatively more efficient, less expensive to construct and less difficult to permit than coal-fired plants has the most potential to continue to displace a significant amount of coal-fired electric power generation in the near term. Federal and state mandates for increased use of electricity derived from renewable energy sources have also adversely affected demand for coal-fired electric power generation. Such mandates make alternative fuel sources more competitive with coal-fired electric power generation.

Changes in federal and state mandates that would include an acceleration in the use of electricity derived from renewable energy sources could result in a decrease in coal consumption by the electric power generation industry and the Company’s customers.

Certain of the Coal Mining segment’s customers, including MLMC's customer, benefit or have benefited from a tax credit under Section 45 of the Internal Revenue Code. The benefit results in a reduction to the cost of coal-fired electric power generation. The elimination or expiration of the Section 45 tax credit would increase the cost of the coal-fired electric power generation from these facilities and could result in the power these facilities produce being less economical than other sources of power generation, which could reduce demand and result in a decrease in coal consumption.

Any of these risks could result in a decrease in coal consumption by the Company’s customers and could have a material adverse effect on the Company’s business, financial condition and results of operations.

Government regulations could impose costly requirements on the Company and its customers.

The coal mining industry and the electric generation industry are subject to extensive regulation by federal, state and local authorities on matters concerning the health and safety of employees, land use, stream and wetland protection, permit and licensing requirements, air and water quality standards, plant and wildlife protection, reclamation and restoration of mining properties after mining, the discharge of GHGs and other materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Legislation mandating certain benefits for current and retired coal miners also affects the industry. Mining operations require numerous governmental and regulatory permits and approvals. The Company is required to prepare and present to federal, state or local authorities data pertaining to the impact the production and combustion of coal may have upon the environment. The public, including non-governmental organizations, opposition groups and individuals, have statutory rights to comment upon and submit objections to requested permits and approvals and to legally challenge certain permits subsequent to their issuance. Compliance with these requirements is costly and time-consuming and may delay commencement or continuation of development or production. New legislation and/or regulations and orders may materially adversely affect the Company's mining operations or its cost structure, or its customers. All of these factors could significantly reduce the Company's profitability. See “Item 1. Business — Government Regulation" on page 9 in this Form 10-K for further discussion.

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The Company is subject to burdensome federal and state mining regulations and the assumptions underlying the Company's reclamation and mine closure obligations could be materially inaccurate.

Federal and state statutes require the Company to restore mine property in accordance with specified standards and an approved reclamation plan, and require that the Company obtain and periodically renew permits for mining operations. Regulations require the Company to incur the cost of reclaiming current mine disturbance at operations where the Company holds the mining permit. Estimates of the Company's total reclamation and mine closing liabilities are based upon permit requirements and the Company's engineering expertise related to these requirements. While management regularly reviews the estimated reclamation liabilities and believes that appropriate accruals have been recorded for all expected reclamation and other costs associated with closed mines, the estimate can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Such changes could have a material adverse effect on the Company’s business and could significantly reduce its profitability.

The Clean Air Act ("CAA") could reduce the demand for coal.

The process of burning coal can cause many compounds and impurities in the coal to be released into the air, including carbon dioxide, sulfur dioxide, nitrogen oxides, mercury, particulates and other matter. The CAA and the corresponding state laws that extensively regulate the emissions of materials into the air affect coal mining operations both directly and indirectly. Direct impacts on coal mining operations occur through CAA permitting requirements and/or emission control requirements relating to air contaminants, especially particulate matter. Indirect impacts on coal mining operations occur through regulation of the air emissions of carbon dioxide, sulfur dioxide, nitrogen oxides, mercury, particulate matter and other compounds emitted by coal-fired power plants. The EPA has discussed issuing or issued regulations that impose tighter emission restrictions on a number of these compounds, some of which are currently subject to litigation. The general effect of tighter restrictions is to reduce demand for coal. A reduction in coal’s share of the capacity for power generation could have a material adverse effect on the Company’s business, financial condition and results of operations. See “Item 1. Business — Government Regulation" on page 9 in this Form 10-K for further discussion.

The Coal Mining segment's customers' operations require significant capital expenditures.

Maintaining and installing environmental controls on power plants requires significant capital expenditures. Any delay or reduction in making capital expenditures to maintain or upgrade coal-fired power plants by the Coal Segment's customers, principally electric utilities, could result in an increase in outage days and a corresponding decrease in coal consumption. A decrease in coal consumption could have a material adverse effect on the Coal Mining segment's financial condition, results of operations and cash flows.

Mining operations are vulnerable to weather and other conditions that are beyond the Company's control.

Many conditions beyond the Company's control can decrease the delivery, and therefore the use, of coal to the Company's customers. These conditions include weather, pandemics, adverse mining conditions, unexpected maintenance problems and shortages of replacement parts, any of which could significantly reduce the Company's profitability.

The Company faces numerous uncertainties in estimating economically recoverable reserves and resources, and inaccuracies in estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.

Information concerning the Company's mining operations in "Item 2 - Properties on page 31" has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K, which first became applicable to us for the fiscal year ended December 31, 2021. A mineral is economically recoverable when the price at which it can be sold exceeds the costs and expenses of mining, processing and selling the mineral. Forecasts of NACCO's future performance are based on, among other things, estimates of mineral reserves and resources. Mineral reserve and resource estimates of the remaining tons of coal in the Company's operational mines and other mining properties are based on many factors, including engineering, economic and geological data assembled and analyzed by internal staff and third parties, which includes various engineers and geologists, the area and volume covered by mining rights, assumptions regarding extraction rates and duration of mining operations, and the quality of in-place reserves and resources. The reserve and resource estimates as to both quantity and quality are updated from time to time to reflect, among other matters, production of minerals from the Company's mining properties and new mining or other data received.

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There are numerous uncertainties inherent in estimating quantities and qualities of minerals and costs to mine recoverable reserves and resources, including many factors beyond the Company's control. Estimates of mineral reserves and resources necessarily depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include:

•Geologic and mining conditions, including the Company's ability to access certain mineral deposits as a result of the nature of the geologic formations of coal deposits or other factors, which may not be fully identified by available exploration data and may differ from past experience;

•Demand for the Company's minerals;

•Contractual arrangements, operating costs and capital expenditures;

•Development and reclamation costs;

•Mining technology and processing improvements;

•The effects of regulation by governmental agencies;

•The ability to obtain, maintain and renew all required permits;

•Employee health and safety; and

•NACCO's ability to convert all or any part of mineral resources to economically extractable mineral reserves.

As a result, actual tonnage recovered from identified mining properties and estimated revenues, expenditures and cash flows with respect to reserves and resources may vary materially from estimates. Thus, these estimates may not accurately reflect the Company’s actual reserves and resources. Any material inaccuracy in estimates related to the Company's reserves or resources could result in lower than expected revenues, higher than expected costs or decreased profitability and changes in future cash flow, which could materially and adversely affect the Company business, results of operations, financial position and cash flows. Additionally, reserve and resource estimates may be adversely affected in the future by interpretations of, or changes to, the SEC’s property disclosure requirements for mining companies.

A defect in title or the loss of a leasehold interest in certain property could limit the Company's ability to mine coal reserves or result in significant unanticipated costs.

The Company conducts a significant part of its coal mining operations on leased properties. A title defect or the loss of a lease could adversely affect the ability to mine the associated coal reserves. The Company may not verify title to leased properties or associated coal reserves until the Company has committed to developing those properties or coal reserves. The Company may not commit to develop property or coal reserves until the Company has obtained necessary permits and completed exploration. As such, the title to property that the Company intends to lease or mine may contain defects prohibiting the ability to conduct mining operations. Similarly, leasehold interests may be subject to superior property rights of third parties. In order to conduct mining operations on properties where these defects exist, the Company may incur unanticipated costs. In addition, some leases require the Company to produce a minimum quantity of coal and/or pay minimum production royalties. The Company's inability to satisfy those requirements may cause the leasehold interest to terminate.

Risks related to the NAMining segment

The Company has experienced growth in its NAMining business in recent periods and it may not be able to sustain growth or manage future growth effectively.

The Company has expanded its overall NAMining business, operations and headcount in recent periods. NAMining’s operating expenses may continue to increase as the Company scales the NAMining business, including growth outside of Florida, and provides general and administrative resources to support NAMining’s growth. As NACCO continues to grow the NAMining business, the Company must effectively integrate, develop and motivate new employees, as well as existing employees who are promoted or moved into new roles, while maintaining the effectiveness of its business execution. In part, NAMining’s success depends on its ability to integrate new customers in an efficient and effective manner. The Company anticipates that it will continue to incur costs and capital expenditures associated with future growth prior to realizing the full measure of anticipated long-term benefits, and the return on these investments may be lower, may develop more slowly than expected or may never be realized. If the Company is unable to manage this growth and the associated expenses effectively, the Company may not be able to take advantage of market opportunities or remain competitive. The Company may also fail to execute on its business plan or respond to competitive pressures, any of which could adversely affect the NAMining business, operating results and financial condition.

NAMining faces competition from aggregates producers that choose to self-perform mining operations and from other mining companies.

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NAMining faces competition from existing and prospective customers that are capable of performing, or engaging other companies to perform the services NAMining provides. NAMining cannot be certain that its existing customers will continue to outsource these services to NAMining in the future, which could adversely affect the NAMining business, operating results and financial condition.

The Company is subject to risks involved in the development of new mining projects.

From time to time, the Company seeks to develop new mining projects, including the Thacker Pass project. The risks associated with such projects can be substantial. New mining projects can take up to several years to complete, are complex and require significant capital expenditures. These projects are subject to significant risks, including delays, extreme weather events, unexpected increases in the cost of required materials, and disputes with third party providers of materials, equipment or services, and a completed project may not yield the anticipated operational or financial benefit, any of which could have a material adverse effect on the Company’s business, financial condition and results of operations.

NAMining operations are currently geographically concentrated and therefore subject to regional economic risk, regulatory conditions, natural disasters, severe weather events or other circumstances affecting Florida.

As of December 31, 2021, over 80% of the quarries NAMining operates are located in Florida. A prolonged economic downturn or adverse change in regulatory conditions in the Florida mining or construction industry could result in a significant reduction in demand for NAMining’s services. The occurrence of one or more natural disasters, severe weather events, terrorist attacks, or disruptive political events in Florida could adversely affect the NAMining business.

Risks related to the Minerals Management segment

The Company has no control over the timing of the development and operation of its natural gas, oil and coal reserves extracted by third parties.

The Company owns mineral and royalty interests in the continental United States. The Company does not develop oil and gas reserves and is not a natural gas and oil producer. The Company derives income from royalty-based leases under which lessees make payments to the Company based on their sale of natural gas, oil and coal. As discussed in “Item 1. Business — Business Developments" on page 2, the Company acquired additional mineral and royalty interests during 2021 and 2020 and plans to continue to pursue acquisitions of additional mineral and royalty interests. Future royalty-based income is dependent on the number of oil and gas wells being developed and operated on the Company’s mineral acreage. The decision to pursue development and operation of oil and gas wells is made by third-party operators, not by the Company, and depends on a number of factors outside of the Company's control, including fluctuations in commodity prices (primarily natural gas), regulatory risk, the Company's lessees' willingness and ability to incur well-development and other operating costs, the rate of production of the reserves and changes in the availability and continuing development of infrastructure. Lower commodity prices may reduce the amount of oil and natural gas that third-party operators can produce economically. In the event that new federal or state restrictions related to the hydraulic fracturing process are adopted in areas where the Company owns mineral and royalty interests, the Company’s lessees may incur additional costs or permitting requirements to comply with such requirements that may be significant and could result in added restrictions, delays or curtailments in the pursuit of exploration, development, or production activities. In addition, if a lessee were to experience financial difficulty, the lessee might not be able to pay its royalty payments or continue operations. A failure on the part of the lessee to make royalty payments gives the Company the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If the Company repossessed any of its properties, it would seek a replacement lessee. However, the Company may not be able to find a replacement lessee and, if it did, the Company might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, if the Company is able to enter into a new lease with a new lessee, the replacement lessee may not achieve the same levels of production or sales prices as the lessee it replaced. Any of these risks could materially reduce the Company’s expected royalty income and the Company’s profitability.

Minerals are a depleting asset. Unless the Company replaces existing mineral and royalty interests with new mineral and royalty interests and third-party lessees develop those mineral and royalty interests, the Company’s reserves and royalty income will decline.

Producing oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless the Company’s third-party lessees conduct successful ongoing well development activities or the Company continually acquires mineral and royalty interests, production and income related to the Company’s mineral and royalty interests will decline as those reserves are depleted. The future cash flow and results of operations of the Minerals Management segment are highly dependent on third-party operators’ success in developing the

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Company’s current and future mineral and royalty interests. These operators may not have access to the capital needed to develop the Company's mineral interests. The Company may not be able to acquire or find sufficient additional mineral and royalty interests to replace third-party operators' current and future production. Further, the decline curve the Company uses to project future royalty income is subject to numerous assumptions and limitations. Natural gas wells have high initial production rates and follow a natural decline before settling into relatively stable, long-term production. Decline rates can vary due to factors like well depth, well length, formation pressure, and facility design. Any of these risks could materially reduce the Company’s expected royalty income and the Company’s profitability.

Substantially all of the Minerals Management segment’s revenues are derived from royalty payments that are based on the price at which oil and natural gas produced from the acreage underlying the Company’s interests are sold. Prices of oil and natural gas are volatile due to factors beyond the Company’s control. A substantial or extended decline in commodity prices may adversely affect the Minerals Management segment’s financial condition or results of operations.

The Minerals Management segment’s revenues and operating results depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond the Company's control; market expectations about future prices of oil and natural gas; the level of global oil and natural gas exploration and production; the cost of exploring for, developing, producing and delivering oil and natural gas; the price and quantity of foreign imports and U.S. exports of oil and natural gas; the level of U.S. domestic production; political and economic conditions in oil producing regions; the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; trading in oil and natural gas derivative contracts; the level of consumer product demand; weather conditions and natural disasters; technological advances affecting energy consumption, energy storage and energy supply; domestic and foreign governmental regulations and taxes; the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East and economic sanctions such as those imposed by the U.S. on oil and gas exports from Iran; the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; the price and availability of alternative fuels; and overall domestic and global economic conditions. A substantial or extended decline in commodity prices may adversely affect the Minerals Management segment’s financial condition or results of operations.

Risks related to corporate structure

The Company’s stock repurchase program could affect the price of NACCO’s common stock and increase volatility and may not enhance long-term shareholder value.

The Company’s Board of Directors has authorized a stock repurchase program. The timing and amount of any repurchases under the stock repurchase program are determined at the discretion of the Company's management based on a number of factors, including the availability of capital, other capital allocation alternatives, market conditions for the Company's Class A common stock and other legal and contractual restrictions. The stock repurchase program does not require the Company to acquire any specific number of shares and may be modified, suspended, extended or terminated without prior notice and may be executed through open market purchases, privately negotiated transactions or otherwise.

Repurchases under the stock repurchase program could affect the price of the Company's Class A common stock. The existence of a stock repurchase program could cause the price of the Company's Class A common stock to be higher than it would be in the absence of such a program and could potentially reduce the market liquidity for the Company’s Class A common stock. There can be no assurance that any stock repurchases will enhance shareholder value because the market price of the Company’s Class A common stock may decline below the levels at which the Company repurchased the shares. Although the stock repurchase program is intended to enhance long-term shareholder value, there is no assurance that it will do so and short-term price fluctuations in the Class A common stock could reduce the program’s effectiveness. Furthermore, the stock repurchase program does not obligate the Company to repurchase any dollar amount or number of shares of the Company's Class A common stock, and it may be suspended or discontinued at any time and any suspension or discontinuation could cause the market price of the Company's Class A common stock to decline.

The price of NACCO's securities may be volatile.

The price of the Company's common stock may fluctuate due to a variety of market and industry factors that may materially reduce the market price of NACCO's common stock regardless of operating performance, including, among others: (i) actual or anticipated fluctuations in the Company's quarterly and annual results and those of other public companies in the industry; (ii) industry cycles and trends; (iii) changes in government regulation; (iv) potential or actual military conflicts or acts of terrorism;

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(v) announcements concerning NACCO, its customers or its competitors; (vi) lack of trading liquidity as a result of low trading volumes could make it difficult for investors to sell shares; and (vii) the general state of the securities market. In addition, the stock market in general has experienced significant volatility that often has been unrelated to the operating performance of companies whose shares are traded. These market fluctuations could adversely affect the trading price of the Company's common stock, regardless of NACCO's actual operating performance. As a result of all of these factors, investors in the Company's common stock may not be able to resell their stock at or above the price they paid or at all. Further, NACCO could be the subject of securities class action litigation due to any such stock price volatility, which could divert management’s attention and have a material adverse effect on the Company's operating results.

The amount and frequency of dividend payments made on NACCO's common stock could change.

The Board of Directors has the power to determine the amount and frequency of the payment of dividends. Decisions regarding whether or not to pay dividends and the amount of any dividends are based on earnings, capital and future expense requirements, financial conditions and other factors the Board of Directors may consider. Accordingly, holders of NACCO's common stock should not rely on past payments of dividends in a particular amount as an indication of the amount of dividends that will be paid in the future.

NACCO's certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.

Provisions contained in the Company's certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire the Company, even if doing so might be beneficial to NACCO's stockholders. Provisions of the Company's by-laws and certificate of incorporation impose various procedural and other requirements that could make it more difficult for stockholders to affect certain corporate actions. These provisions could limit the price that certain investors might be willing to pay in the future for shares of NACCO's common stock and may have the effect of delaying or preventing a change in control.

NACCO is a smaller reporting company and cannot be certain if the reduced disclosure requirements applicable to smaller reporting companies will make the Company's common stock less attractive to investors.

The Company is currently a “smaller reporting company” as defined in the Securities Exchange Act of 1934, and thus allowed to provide simplified executive compensation disclosures and other decreased disclosure in SEC filings. The reduced disclosures may make it more difficult to compare the Company's performance with other public companies.

NACCO cannot predict whether investors will find the Company's common stock less attractive because of these exemptions. If some investors find NACCO's common stock less attractive as a result, there may be a less active trading market for the Company's common stock and the stock price may be more volatile.

Certain members of the Company's extended founding family own a substantial amount of its Class A and Class B common stock and, if they were to act in concert, could control the outcome of director elections and other stockholder votes on significant corporate actions.

The Company has two classes of common stock: Class A common stock and Class B common stock. Holders of Class A common stock are entitled to cast one vote per share and, as of December 31, 2021, accounted for approximately 26 percent of the voting power of the Company. Holders of Class B common stock are entitled to cast ten votes per share and, as of December 31, 2021, accounted for the remaining voting power of the Company. As of December 31, 2021, certain members of the Company's extended founding family held approximately 34 percent of the Company's outstanding Class A common stock and approximately 98 percent of the Company's outstanding Class B common stock. On the basis of this common stock ownership, certain members of the Company's extended founding family could have exercised approximately 81 percent of the Company's total voting power. Although there is no voting agreement among such extended family members, in writing or otherwise, if they were to act in concert, they could control the outcome of director elections and other stockholder votes on significant corporate actions, such as certain amendments to the Company's certificate of incorporation and sales of the Company or substantially all of its assets. Because certain members of the Company's extended founding family could prevent other stockholders from exercising significant influence over significant corporate actions, the Company may be a less attractive takeover target, which could adversely affect the market price of its common stock.

General Risk Factors

The Company’s effective income tax rate could be volatile and materially change as a result of changes in tax laws, mix of earnings and other factors.

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The Company is subject to income taxes in the United States and the effective income tax rate is impacted by certain U.S. federal income tax benefits currently available to coal mining and oil and gas exploration and development companies. Future results of operations could be affected by changes in the Company’s effective income tax rate as a result of an increase in the statutory tax rate or the reduction or elimination of percentage depletion as well as changes in the mix of earnings between entities that benefit from percentage depletion and those that do not.

Current and future capital and credit market conditions could adversely affect the Company’s ability to obtain bank financing on reasonable terms. Certain financial institutions have acted to limit available financing for companies in the fossil fuel industry, including coal mining, which could result in increases in costs of borrowing or in the Company’s ability to maintain financing at current levels.

The Company may be unable to obtain financing on reasonable terms. Historically, the Company has addressed its liquidity needs (including funds required to pay dividends and fund working capital and planned capital expenditures) with operating cash flow and borrowings under credit facilities. The Company’s wholly-owned subsidiary, NACoal, has a revolving line of credit of up to $150.0 million that expires in November 2025 (the "NACoal Facility"). The Company’s ability to access the capital markets and the costs and terms of available financing depends on many factors, including perceived credit risks of companies with coal and/or oil and gas exposure as a result of current market sentiment for fossil fuels. Certain financial institutions have taken actions to limit available financing to entities that produce or use fossil fuels. The volatility in the energy industry combined with recent bankruptcies and additional perceived credit risks of companies with coal and/or oil and gas exposure has resulted in traditional bank lenders seeking to reduce or eliminate their lending exposure to these companies. An inability to obtain bank financing, or obtaining a refinancing with terms that are not as favorable as the existing terms of such indebtedness, could have a material adverse effect on the Company's operating results and financial condition.

Failure to obtain financial assurance to secure reclamation and other long-term obligations, including surety bonds and letters of credit on acceptable terms, could affect NACCO's ability to mine.

Federal and state laws require the Company to provide financial assurance or financial security to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers’ compensation and black lung benefits costs, leases and other obligations. Future federal and state laws and regulations may require higher amounts of financial security, including as a result of changes to certain factors used to calculate the bonding or security amounts. Bond issuers may demand higher fees or additional collateral, including cash or letters of credit or other terms less favorable upon renewals. As the Company is required by state and federal law to have bonds or other acceptable security in place before mining can commence or continue, the failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect NACCO's ability to mine. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of the Company's financing arrangements. In addition, as a result of increasing credit pressures on the coal industry, it is possible that surety bond providers could demand cash collateral as a condition to providing or maintaining surety bonds. Any such demands, could have a material adverse impact on the Company’s liquidity and financial position. If the Company is unable to meet collateral requirements and cannot otherwise obtain or retain required surety bonds, it may be unable to satisfy legal requirements necessary to conduct mining operations. Difficulty in acquiring surety bonds, or additional collateral requirements, would increase the Company’s costs and likely require greater use of alternative sources of funding for this purpose, which would reduce the Company’s liquidity.

Insurance coverage is increasingly expensive, contains more stringent terms and may be difficult to obtain in the future. A number of global insurance companies have taken steps to limit coverage for companies in the fossil fuel industry, including coal mining, which could result in significant increases in costs of insurance or in the Company’s ability to maintain insurance coverage at current levels.

The Company holds a number of insurance policies, including director and officers’ liability and property and casualty insurance coverages. Because the Company is involved in coal mining, costs of insurance may increase substantially or insurance carriers may limit or decide not to insure the Company in the future. In addition, if the Company makes significant insurance claims under the Company’s insurance policies, such claims may have a material adverse effect on its ability to obtain future insurance coverage at commercially reasonable rates. Limited, or an inability to obtain, insurance coverage, significant increases in the premiums or deductibles of insurance, or losses in excess of its liability insurance coverage limits, could have a material adverse effect on the Company's operating results and financial condition.

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Increasing emphasis and changing expectations with respect to environmental, social and governance matters may impose additional costs on the Company or expose the Company to new or additional risks.

Expectations relating to environmental, social and governance (“ESG”) matters have been rapidly evolving and increasing. Government organizations are enhancing or advancing legal and regulatory requirements specific to ESG matters. The heightened focus on ESG issues requires the continuous monitoring of various and evolving laws, regulations, standards and expectations and the associated reporting requirements. Investor advocacy groups, certain institutional investors, investment funds and other influential investors are also increasingly focused on ESG practices. The Company could face pressures from investors, who are increasingly focused on climate change, to prioritize sustainable energy practices, reduce the Company’s carbon footprint and promote sustainability. Investors may request the Company implement ESG procedures or standards as a condition to maintain their investment or to make further investments. Lenders and insurers may also limit lending to and insuring of companies that do not meet certain ESG measures endorsed by them. Additionally, the Company may face reputational challenges in the event its ESG practices are inconsistent with the third party views of acceptable ESG practices. Companies which do not adapt to or comply with regulatory, investor or stakeholder expectations and standards, which are evolving, or which are perceived to have not responded appropriately, may suffer from reputational damage and the business, financial condition, and/or stock price of such a company could be materially and adversely affected.

The Company may be subject to litigation seeking to hold energy companies accountable for the effects of climate change.

Increasing attention to climate change risk has also resulted in a recent trend of governmental investigations and private litigation by local and state governmental agencies as well as private plaintiffs in an effort to hold energy companies accountable for the effects of climate change. Other public nuisance lawsuits have been brought in the past against power, coal, oil and gas companies alleging that their operations are contributing to climate change. The plaintiffs in these suits sought various remedies, including punitive and compensatory damages and injunctive relief. While the U.S. Supreme Court held that any federal common law had been displaced by the CAA and thus dismissed the public nuisance claims against the defendants in those cases, tort-type liabilities remain a possibility and a source of concern. We could incur substantial legal costs associated with defending such lawsuits in the future. Government entities in certain states have brought similar claims seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the GHG emissions attributable to those fuels or for other grounds related to climate change, such as improper disclosure of climate change risks. Those lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement under various tort theories. We have not been made a party to these suits, but it is possible that we could be included in similar future lawsuits initiated by state and local governments as well as private claimants.

The Company’s business could suffer if NACCO’s information technology systems are disrupted, cease to operate effectively or if the Company experiences a security breach, a cyber incident or cyber attack.

Like many other companies, the Company is the target of malicious cyber attack attempts in the normal course of business. Cybersecurity incidents involving businesses and other institutions are on the rise. Cyber threats are rapidly evolving and those threats and the means for obtaining access to information in digital and other storage media are becoming increasingly sophisticated. Cyber threats and cyber attackers can be sponsored by nation states or sophisticated criminal organizations or be the work of independent hackers.

As cyber threats evolve and become more difficult to detect and successfully defend against, one or more cyber attacks might defeat the Company's or a third-party service provider's security measures in the future. Employee error or other irregularities may also result in a failure of security measures and a breach of information systems. Moreover, hardware, software or applications the Company may use have inherent defects of design, manufacture or operations or could be inadvertently or intentionally implemented or used in a manner that could compromise information security.

A security breach and loss of information may not be discovered for a significant period of time after it occurs. Any compromise of data security could result in a violation of applicable privacy and other laws or standards, the loss of valuable business data, or a disruption of the Company's business. A security breach involving the misappropriation, loss or other unauthorized disclosure of sensitive or confidential information could give rise to unwanted media attention, materially damage customer relationships and the Company's reputation, and result in fines, fees, or liabilities, which may not be covered by insurance policies.

The Company relies on information technology systems to operate its business and to record and process transactions; respond to customer inquiries; purchase supplies; provide services; deliver inventory on a timely basis; and maintain cost-efficient

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operations. Despite the Company's efforts, the Company’s information technology systems may be vulnerable, from time to time, to damage or interruption from user error, computer viruses, power outages, third-party intrusions and other technical malfunctions.

Through the Company’s business operations, the Company collects and stores confidential information from its customers and vendors and personal information and other confidential information from its employees. Although the Company has taken steps designed to safeguard such information, there can be no assurance that such information will be protected against unauthorized access, use or disclosure. Unauthorized parties may penetrate the Company’s or its vendors’ network security and, if successful, misappropriate such information. Additionally, methods to obtain unauthorized access to confidential information change frequently and may be difficult to detect, which can impact the Company’s ability to respond appropriately.

The Company could be subject to liability for failure to comply with privacy and information security laws, for failing to protect personal information or for failing to respond appropriately. Loss, unauthorized access to, or misuse of confidential or personal information could disrupt the Company’s operations, damage the Company’s reputation, and expose the Company to claims from customers, financial institutions, regulators, employees and other persons, any of which could have an adverse effect on the Company’s business, financial condition and results of operations.

Security breaches, cyber incidents or cyber attacks could include, among other things, computer viruses, malicious or destructive code, ransomware, social engineering attacks (including phishing and impersonation), hacking, denial of service attacks and other attacks. Cybersecurity threats to, and incidents involving, vendors and other third-parties who support the Company's activities could impact us. For example, although the Company has not experienced any material impacts from the SolarWinds Orion cybersecurity breach that was widely publicized in December 2020, similar future events could have a material impact on the Company. The Company is continuously installing new and upgrading existing information technology systems. The Company uses employee awareness training around phishing, malware, and other cyber risks. The Company believes these incidents are likely to continue and is unable to predict the direct or indirect impact of future attacks or breaches to business operations.

The Company’s results of operations, financial condition, cash flows and stock price could be adversely affected by pandemics, epidemics or other public health emergencies, such as the global outbreak of COVID-19. The COVID-19 pandemic resulted in governments around the world implementing stringent measures to help control the spread of the virus. Although the Company has continued to operate facilities consistent with federal guidelines and state and local orders, the ongoing COVID-19 pandemic and the preventive or protective actions taken by governmental authorities may have a material adverse effect on the Company’s operations, work force, supply chain or customers, including business shutdowns or disruptions. The extent to which COVID-19 may adversely impact the Company's businesses depends on future developments, which are highly uncertain and unpredictable, including the extent of new outbreaks, the extent to which additional actions to mitigate the COVID-19 pandemic may be needed, the nature of government public health guidelines and the public's adherence to those guidelines. Any resulting financial impact cannot reasonably be estimated at this time, but could have a material adverse effect on the Company’s financial condition, cash flows and results of operations.

Even after the COVID-19 pandemic has subsided, the Company may experience material adverse effects due to a decline in economic activity.

The Company’s operations could be disrupted by natural or human causes beyond its control.

The Company’s operations are subject to disruption from natural or human causes beyond its control, including physical risks from hurricanes, severe storms, floods and other forms of severe weather, accidents, fires, earthquakes, terrorist acts and epidemic or pandemic diseases such as the coronavirus, any of which could result in suspension of operations or harm to people or the environment. While all of the Company’s operations are located in the United States, the Company participates in a global supply chain, and if a disease spreads sufficiently to cause a pandemic (or to cause the fear of a pandemic to rise) or governments regulate or restrict the flow of labor or products or impede the travel of Company personnel, the Company’s ability to conduct normal business operations could be impacted which could adversely affect the Company’s results of operations and liquidity.

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Item 1B. UNRESOLVED STAFF COMMENTS

None.

Item 2. PROPERTIES

Coal Mining Segment - Operations

NACCO-owned Resources and Reserves

1.0 INTRODUCTION

Information concerning the Company’s mining properties in this Form 10-K have been prepared in accordance with the requirements of subpart 1300 of Regulation S-K, which first became applicable to the Company for the year ended December 31, 2021. These requirements differ significantly from the previously applicable disclosure requirements of SEC Industry Guide 7. Among other differences, subpart 1300 of Regulation S-K requires the Company to disclose its mineral resources, in addition to its mineral reserves, both in the aggregate and for each of the Company’s individually material mining properties.

As used in this Report on Form 10-K, the terms “mineral resource,” “measured mineral resource,” “indicated mineral resource,” “inferred mineral resource,” “mineral reserve,” “proven mineral reserve” and “probable mineral reserve” are defined and used in accordance with subpart 1300 of Regulation S-K. Under subpart 1300 of Regulation S-K, mineral resources may not be classified as “mineral reserves” unless the determination has been made by a qualified person that the mineral resources can be the basis of an economically viable project. Readers are specifically cautioned not to assume that any part or all of the mineral deposits (including any mineral resources) in these categories will ever be converted into mineral reserves, as defined by the SEC.

Readers are cautioned that, except for that portion of mineral resources classified as mineral reserves, mineral resources do not have demonstrated economic value. Inferred mineral resources are estimates based on limited geological evidence and sampling and have a too high of a degree of uncertainty as to their existence to apply relevant technical and economic factors likely to influence the prospects of economic extraction in a manner useful for evaluation of economic viability. Estimates of inferred mineral resources may not be converted to a mineral reserve. It cannot be assumed that all or any part of an inferred mineral resource will ever be upgraded to a higher category. A significant amount of exploration must be completed in order to determine whether an inferred mineral resource may be upgraded to a higher category. Therefore, readers are cautioned not to assume that all or any part of an inferred mineral resource exists, that it can be the basis of an economically viable project, or that it will ever be upgraded to a higher category. Likewise, readers are cautioned not to assume that all or any part of measured or indicated mineral resources will ever be converted to mineral reserves. See "Item 1A - “Risk Factors” on page 20.

The information that follows is derived, for the most part, from, and in some instances is an extract from, the technical report summaries (“TRS’s”) prepared in compliance with the Item 601(b)(96) and subpart 1300 of Regulation S-K. Portions of the following information are based on assumptions, qualifications and procedures that are not fully described herein. Reference should be made to the full text of the TRS’s, incorporated herein by reference and made a part of this Report on Form 10-K.

TCoteau, Coyote Creek, Falkirk and MLMC, collectively referred to as “Mines subject to SEC Section 1300 reporting”, each wholly-owned subsidiaries of NACCO, operate surface coal mines under long-term contracts with power generation companies pursuant to a service-based business model. At each of these mines, the Company owns or controls the mineral resources and reserves.

The Company operates additional surface coal mines where the customer owns or controls the reserves. The Company conducts activities to extract these customer-owned reserves pursuant to long-term contracts.

Locations of the properties subject to SEC Section 1300 reporting are shown in Figure 1.1 Surface Coal Mines Operational During 2021 Subject to SEC Section 1300 reporting.

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Figure 1.1 Surface Coal Mines Operational During 2021 Subject to SEC Section 1300 Reporting

At all Mines subject to SEC Section 1300 Reporting other than MLMC, the Company is paid a management fee per ton of coal or heating unit (MMBtu) delivered. Each contract specifies the indices and mechanics by which fees change over time, generally in line with broad measures of U.S. inflation. The customers are responsible for funding all mine operating cost, including final mine reclamation, and directly or indirectly providing all of the capital required to build and operate the mine. This contract structure eliminates the Company's exposure to spot coal market price fluctuations.

A summary of coal production at the Mines subject to SEC Section 1300 Reporting for the past three years has been tabulated and is presented on Table 1.1 Production Summary.


	Tons (in millions)
	2019	2020	2021
The Coteau Properties Company	13.5	12.6	12.5
The Falkirk Mining Company	7.4	7.2	7.9
Coyote Creek Mining Company	1.7	2	2
Mississippi Lignite Mining Company	2.6	2.5	3
Totals	25.2	24.3	25.4

Table 1.1 Production Summary

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2.0 MATERIAL MINING PROPERTIES

2.1 Freedom Mine — The Coteau Properties Company

The Freedom Mine generally produces between 12.5 million and 13.5 million tons of lignite coal annually. The mine started delivering coal in 1983. All production from the mine is delivered to Dakota Coal Company, a wholly owned subsidiary of Basin Electric. Dakota Coal Company then sells the coal to the Synfuels Plant, Antelope Valley Station and Leland Olds Station, all of which are operated by affiliates of Basin Electric. The Synfuels Plant is a coal gasification plant that manufactures synthetic natural gas and produces fertilizers, solvents, phenol, carbon dioxide, and other chemical products for sale.

During 2020, Basin Electric informed Coteau that it is considering changes that may result in modifications to its Synfuels Plant that could potentially reduce or eliminate coal requirements at the Synfuels Plant. Basin Electric indicated that if it decides to proceed with any changes that could reduce or eliminate the use of coal, the feedstock change is not expected to occur before 2026.

During August 2021, Bakken and Basin Electric signed a non-binding term sheet to purchase the assets of the Synfuels Plant. Bakken stated the closing date is expected to be April 1, 2023. As part of the term sheet between Basin Electric and Bakken, Basin Electric indicated that the Synfuels Plant will continue existing operations through 2025. The closing is subject to the satisfaction of specified conditions. Basin Electric is also considering other options for the Synfuels Plant if the transaction with Bakken does not close.

The Freedom Mine, operated by Coteau, is located approximately 90 miles northwest of Bismarck, North Dakota. The main entrance to the Freedom Mine is accessed by means of a paved road and is located on County Road 15. Coteau holds 380 leases granting the right to mine approximately 34,016 acres of coal interests and the right to utilize approximately 23,455 acres of surface interests. In addition, Coteau owns in fee 33,805 acres of surface interests and 4,107 acres of coal interests. Substantially all of the leases held by Coteau were acquired in the early 1970s and have been replaced with new leases or have lease terms for a period sufficient to meet Coteau’s contractual production requirements.

The reserves are located in Mercer County, North Dakota, starting approximately two miles north of Beulah, North Dakota. The center of the basin is located near the city of Williston, North Dakota, approximately 100 miles northwest of the Freedom Mine. The economically mineable coal in the reserve occurs in the Sentinel Butte Formation, and is overlain by the Coleharbor Formation. The Coleharbor Formation unconformably overlies the Sentinel Butte Formation. It includes all of the unconsolidated sediments resulting from deposition during glacial and interglacial periods. Lithologic types include gravel, sand, silt, clay and till. The modified glacial channels are in-filled with gravels, sands, silts and clays overlain by till. The coarser gravel and sand beds are generally limited to near the bottom of the channel fill. The general stratigraphic sequence in the upland portions of the reserve area consists of till, silty sands and clayey silts.

Coteau currently has all permits in place for the Freedom Mine to operate through 2031. Permit expansions required to extend the life of the mine through 2045 will be acquired as needed. No mineral processing occurs at the Freedom Mine.

2.2 Falkirk Mine — The Falkirk Mining Company

The Falkirk Mine generally produces between 7 million and 8 million tons of lignite coal annually. The mine started delivering coal in 1978 primarily for the Coal Creek Station, an electric power generating station owned by GRE. In 2014, Falkirk began delivering coal to Spiritwood Station, another electric power generating station owned by GRE.

In May 2020, GRE announced its intent to sell or retire Coal Creek Station and modify Spiritwood Station to be fueled by natural gas. During June 2021, GRE entered into an agreement to sell Coal Creek Station and the adjacent high-voltage direct current transmission line to Bismarck, North Dakota-based Rainbow Energy and its affiliates. The closing of this sale is subject to the satisfaction of certain conditions and presently, the transaction is expected to close in the second quarter of 2022.

The Falkirk Mine, operated by Falkirk, is located approximately 50 miles north of Bismarck, North Dakota on a paved access road off U.S. Highway 83. Falkirk holds 335 leases granting the right to mine approximately 43,486 acres of coal interests and the right to utilize approximately 24,324 acres of surface interests. In addition, Falkirk owns in fee 40,666 acres of surface interests and 1,788 acres of coal interests. Substantially all of the leases held by Falkirk were acquired in the early 1970s with initial terms that have been further extended by the continuation of mining operations.

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The reserves are located in McLean County, North Dakota, from approximately nine miles northwest of the town of Washburn, North Dakota to four miles north of the town of Underwood, North Dakota. Structurally, the area is located on an intercratonic basin containing a thick sequence of sedimentary rocks. The economically mineable coals in the reserve occur in the Sentinel Butte Formation and the Bullion Creek Formation and are unconformably overlain by the Coleharbor Formation. The Sentinel Butte Formation conformably overlies the Bullion Creek Formation. The general stratigraphic sequence in the upland portions of the reserve area (Sentinel Butte Formation) consists of till, silty sands and clayey silts, main hagel lignite bed, silty clay, lower lignite of the hagel lignite interval and silty clays. Beneath the Tavis Creek, there is a repeating sequence of silty to sand clays with generally thin lignite beds.

There are no outstanding permits related to the life of mine ("LOM") plan awaiting regulatory approval. The Falkirk Mining Company currently has all permits in place to operate and adhere to the current mine plan. No mineral processing occurs at the Falkirk Mine.

2.3 Coyote Creek Mine - Coyote Creek Mining Company, LLC

The Coyote Creek Mine generally produces between 1.5 million and 2.0 million tons of lignite annually. The mine began delivering coal in 2016 to the Coyote Station owned by Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Company and Northwestern Corporation. In September 2021, Otter Tail Power Company filed its 2022 Integrated Resource Plan in Minnesota and North Dakota which included its intent to start the process of withdrawal from its 35 percent ownership interest in Coyote Station power plant with an anticipated exit from the plant by December 31, 2028.

The Coyote Creek Mine is located approximately 70 miles northwest of Bismarck, North Dakota. The main entrance to the Coyote Creek Mine is accessed by means of a four-mile paved road extending west off of State Highway 49. Coyote Creek holds a sublease to 86 leases granting the right to mine approximately 8,129 acres of coal interests and the right to utilize approximately 15,168 acres of surface interests. In addition, Coyote Creek Mine owns in fee 160 acres of surface interests and has four easements to conduct coal mining operations on approximately 352 acres.

The reserves are located in Mercer County, North Dakota, starting approximately six miles southwest of Beulah, North Dakota. The center of the basin is located near the city of Williston, North Dakota, approximately 110 miles northwest of the Coyote Creek Mine. The economically mineable coal in the reserve occurs in the Sentinel Butte Formation, and is overlain by the Coleharbor Formation. The Coleharbor Formation unconformably overlies the Sentinel Butte Formation. It includes all of the unconsolidated sediments resulting from deposition during glacial and interglacial periods. Lithologic types include gravel, sand silt, clay and till. The modified glacial channels are in-filled with gravels, sands, silts and clays overlain by till. The coarser gravel and sand beds are generally limited to near the bottom of the channel fill. The general stratigraphic sequence in the upland portions of the reserve area consists of till, silty sands and clayey silts.

2.4 Red Hills Mine — Mississippi Lignite Mining Company

The Red Hills Mine generally produces between 2 million and 3 million tons of lignite coal annually. The Red Hills Mine started delivering coal in 2000. All production from the mine is delivered to its customer's Red Hills Power Plant.

The Red Hills Mine, operated by MLMC, is located approximately 120 miles northeast of Jackson, Mississippi. The entrance to the mine is by means of a paved road located approximately one mile west of Highway 9. MLMC owns in fee approximately 7,343 acres of surface interest and 4,425 acres of coal interests. MLMC holds leases granting the right to mine approximately 5,794 acres of coal interests and the right to utilize approximately 5,597 acres of surface interests. MLMC holds subleases under which it has the right to mine approximately 1,593 acres of coal interest. The majority of the leases held by MLMC were originally acquired during the mid-1970s to the early 1980s with terms extending 50 years, many of which can be further extended by the continuation of mining operations.The lignite deposits of the Gulf Coast are found primarily in a narrow band of strata that outcrops/subcrops along the margin of the Mississippi Embayment. The potentially exploitable tertiary lignites in Mississippi are found in the Wilcox Group. The outcropping Wilcox is composed predominately of non-marine sediments deposited on a broad flat plain.

MLMC currently has all permits in place for the Red Hills Mine to operate and adhere to a mine plan projected through April 2032. No mineral processing occurs at the Red Hills Mine.

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3.0 MINERAL RESOURCES AND RESERVES

Mineral resources and reserves have been summarized from the TRS for each mine subject to SEC Section 1300 reporting and have been included as Table 3.1 and Table 3.2. Qualities are being reported on an as-received moisture basis except for sodium which is from the mineral analysis of ash.


SUMMARY MINERAL RESOURCES AS OF DECEMBER 31, 2021 BASED ON CUT-OFF GRADES OF
Coteau - $1.70/mmBTU, Falkirk - $2.60/mmBTU, Coyote - $2.27/mmBTU, and MLMC - $30.00/ton
	Measured mineral resources
	Tonnage	Grades/qualities
Lignite Coal:		Calorific Value (Btu/lb)	Moisture (%wt)	Ash (%wt)	Sulfur (%wt)	Sodium (%wt)
The Coteau Properties Company	322,310,200	6,779	37.64	7.27	0.89	5.62
The Falkirk Mining Company	78,420,784	6,534	39.83	6.65	0.57	NA
Coyote Creek Mining Company	31,202,000	6,943	36.63	7.25	0.94	7.78
Mississippi Lignite Mining Company	11,475,500	5,110	44.0	14.1	0.60	NA
Total	443,408,484	6,704	38.12	7.34	0.83	5.81

	Indicated mineral resources
	Tonnage	Grades/qualities
Lignite Coal:		Calorific Value (Btu/lb)	Moisture (%wt)	Ash (%wt)	Sulfur (%wt)	Sodium (%wt)
The Coteau Properties Company	8,188,400	6,776	37.92	7.22	0.90	6.36
The Falkirk Mining Company	199,721	6,317	37.10	10.69	0.73	NA
Coyote Creek Mining Company	3,905,900	6,942	36.55	7.39	0.97	7.70
Mississippi Lignite Mining Company	16,169,100	5,270	44.3	14.3	0.7	NA
Total	28,463,121	5,940	41.35	11.29	0.79	6.80

	Measured + indicated mineral resources
	Tonnage	Grades/qualities
Lignite Coal:		Calorific Value (Btu/lb)	Moisture (%wt)	Ash (%wt)	Sulfur (%wt)	Sodium (%wt)
The Coteau Properties Company	330,498,600	6,778	37.64	7.27	0.89	5.63
The Falkirk Mining Company	78,620,505	6,534	39.82	6.66	0.57	NA
Coyote Creek Mining Company	35,107,900	6,943	36.62	7.26	0.94	7.77
Mississippi Lignite Mining Company	27,644,600	5,200	44.2	14.2	0.7	NA
Total	471,871,605	6,657	38.31	7.57	0.83	5.84

	Inferred mineral resources
	Tonnage	Grades/qualities
Lignite Coal:		Calorific Value (Btu/lb)	Moisture (%wt)	Ash (%wt)	Sulfur (%wt)	Sodium (%wt)
The Coteau Properties Company	15,000	6,463	37.84	9.78	1.02	1.59
The Falkirk Mining Company	0	NA	NA	NA	NA	NA
Coyote Creek Mining Company	0	NA	NA	NA	NA	NA
Mississippi Lignite Mining Company	0	NA	NA	NA	NA	NA
Total	15,000	6,463	37.84	9.78	1.02	1.59

Table 3.1 Mineral Resources Summary

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SUMMARY MINERAL RESERVES AS OF DECEMBER 31, 2021 BASED ON CUT-OFF GRADES OF
Coteau - $1.55/mmBTU, Falkirk - $2.60/mmBTU, Coyote - $2.27/mmBTU, and MLMC - $28.04/ton
	Proven mineral reserves
	Tonnage	Grades/qualities
Lignite Coal:		Calorific Value (Btu/lb)	Moisture (%wt)	Ash (%wt)	Sulfur (%wt)	Sodium (%wt)
The Coteau Properties Company	253,946,500	6,779	37.70	7.19	0.89	5.12
The Falkirk Mining Company	78,420,784	6,534	39.83	6.65	0.57	NA
Coyote Creek Mining Company	31,202,000	6,943	36.63	7.25	0.94	7.78
Mississippi Lignite Mining Company	17,167,900	5,070	43.5	15.0	0.6	NA
Total	380,737,184	6,665	38.31	7.44	0.82	5.41

	Probable mineral reserves
	Tonnage	Grades/qualities
Lignite Coal:		Calorific Value (Btu/lb)	Moisture (%wt)	Ash (%wt)	Sulfur (%wt)	Sodium (%wt)
The Coteau Properties Company	3,552,300	6,756	38.29	6.78	0.84	5.40
The Falkirk Mining Company	199,721	6,317	37.10	10.69	0.73	NA
Coyote Creek Mining Company	3,905,900	6,942	36.55	7.39	0.97	7.70
Mississippi Lignite Mining Company	9,447,600	5,080	43.1	15.0	0.6	NA
Total	17,105,521	5,868	40.54	11.50	0.74	6.60

	Total mineral reserves
	Tonnage	Grades/qualities
Lignite Coal:		Calorific Value (Btu/lb)	Moisture (%wt)	Ash (%wt)	Sulfur (%wt)	Sodium (%wt)
The Coteau Properties Company	257,498,800	6,779	37.71	7.19	0.88	5.12
The Falkirk Mining Company	78,620,505	6,534	39.82	6.66	0.57	NA
Coyote Creek Mining Company	35,107,900	6,943	36.62	7.26	0.94	7.77
Mississippi Lignite Mining Company	26,615,500	5,070	43.4	15.0	0.6	NA
Total	397,842,705	6,631	38.41	7.61	0.81	5.44

Table 3.2 Mineral Reserves Summary

Internal Control Disclosure Over Mineral Resources and Reserves

The modeling and analysis of the Company’s resources and reserves has been developed by Company mine personnel and reviewed by several levels of internal management, including the QP, and in some instances, third parties. The development of such resources and reserves estimates, including related assumptions, was a collaborative effort between the QP, Company staff and in some instances, third parties. This section summarizes the internal control considerations for the Company’s development of estimations, including assumptions, used in resource and reserve analysis and modeling.

When determining resources and reserves, as well as the differences between resources and reserves, management developed specific criteria, each of which must be met to qualify as a resource or reserve, respectively. These criteria, such as demonstration of economic viability, points of reference and grade, are specific and attainable. The QP and Company management agree on the reasonableness of the criteria for the purposes of estimating resources and reserves. Calculations using these criteria are reviewed and validated by the QP.

Estimations and assumptions were developed independently for each significant mineral location. All estimates require a combination of historical data and key assumptions and parameters. When possible, resources and data from generally accepted industry sources, such as governmental resource agencies, were used to develop these estimations.

Geological modeling and mine planning efforts serve as a base assumption for resource estimates at each significant coal mining operation. These outputs have been prepared by both Company personnel and third parties, and the methodology is

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compared to industry best practices. Mine planning decisions are determined and agreed upon by Company management. Management adjusts forward-looking models by reference to historic mining results, including by reviewing actual versus predicted levels of production from the mineral deposit, and if necessary, re-evaluating mining methodologies if production outcomes were not realized as predicted. Ongoing mining of the mineral deposit, coupled with product quality validation pursuant to industry best practices and customer expectations, provides further empirical evidence as to the homogeneity, continuity and characteristics of the mineral resource. Ongoing quality validation of production also provides a means to monitor for any potential changes in quality. Also, ongoing monitoring of ground conditions within the mine, surveying for evidence of subsidence and other visible signs of deterioration that may signal the need to re-evaluate rock mechanics and structure of the mine ultimately inform extraction ratios and mine design, which underpin mineral reserve estimates.

Management also assesses risks inherent in mineral resource and reserve estimates, such as the accuracy of geophysical data that is used to support mine planning, identify hazards and inform operations of the presence of mineable deposits. Also, management is aware of risks associated with potential gaps in assessing the completeness of mineral extraction licenses, entitlements or rights, or changes in laws or regulations that could directly impact the ability to assess mineral resources and reserves or impact production levels. Risks inherent in overestimated reserves can impact financial performance when revealed, such as changes in amortizations that are based on life of mine estimates.

Customer-owned Resources and Reserves

South Hallsville No. 1 Mine — The Sabine Mining Company

The South Hallsville No. 1 Mine generally produces between 1.5 million and 2.0 million tons of lignite annually. The mine began delivering coal in 1985. All production from the mine is delivered to Southwestern Electric Power Company's ("SWEPCO") Henry W. Pirkey Plant (the "Pirkey Plant"). SWEPCO is an American Electric Power (“AEP”) company. The mine's reserves and resources are owned and controlled by AEP. The Company conducts activities to extract these customer-owned and controlled reserves.

During 2020, AEP announced its intent to retire the Pirkey Plant in 2023. SWEPCO expects deliveries from Sabine to continue until the first quarter of 2023 at which time Sabine expects to begin final reclamation. Funding for mine reclamation is the responsibility of SWEPCO.

The South Hallsville No. 1 Mine, operated by Sabine, is located approximately 150 miles east of Dallas, Texas on FM 968. The entrance to the mine is by means of a paved road. Sabine has no title, claim, lease or option to acquire any of the reserves at the South Hallsville No. 1 Mine. Southwestern Electric Power Company controls all of the reserves within the South Hallsville No. 1 Mine.

Five Forks Mine — Demery Resources Company, LLC

The Five Forks Mine generally produces between 0.1 million and 0.3 million tons of lignite annually. The mine began delivering coal in 2012 and is located approximately three miles north of Creston, Louisiana on State Highway 153. The mine's reserves and resources are owned and controlled by the customer. The Company conducts activities to extract these customer-owned and controlled reserves.

Access to the Five Forks Mine is by means of a paved road. Demery has no title, claim, lease or option to acquire any of the reserves at the Five Forks Mine. Demery's customer, Five Forks Mining, LLC, controls all of the reserves within the Five Forks Mine.

Facilities and Equipment

The facilities and equipment for each of the coal mines are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, the mines evaluate what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment, and proceed with that replacement.

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The mining method and total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2021 is set forth in the chart below:


Location	Mining Method	Total Historical Cost of Mine Property, Plant and Equipment (excluding Coal Land, Real Estate and Construction in Progress), Net of Applicable Accumulated Amortization, Depreciation and Impairment
		(in millions)
Unconsolidated Mining Operations
Freedom Mine — The Coteau Properties Company	Dragline operation with 3 draglines	$	96.2
Falkirk Mine — The Falkirk Mining Company	Dragline operation with 4 draglines	$	93.8
South Hallsville No. 1 Mine — The Sabine Mining Company	Dragline operation with 4 draglines	$	59.3
Five Forks Mine — Demery Resources Company, LLC	Truck-shovel operation (a)	$	—
Coyote Creek Mine — Coyote Creek Mining Company, LLC	Dragline operation with 1 dragline	$	131.7


Consolidated Mining Operations
Red Hills Mine — Mississippi Lignite Mining Company	Dragline operation with 1 dragline	$	67.9



Other	N/A	$	1.2

(a) Predominantly all of Demery's machinery and equipment is owned by its customer.

NAMining Segment - Operations

NAMining provides contract mining services for independently owned mines and quarries, primarily operating and maintaining draglines at limestone quarries and utilizing other mining equipment at sand and gravel quarries. During 2021, NAMining operated 32 draglines and other equipment at 25 quarries. Of the 32 draglines, 9 are owned by the Company and 23 are owned by customers. At December 31, 2021, NAMining had $35.5 million in property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment.

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The mining process at the limestone mines involves excavating limestone from a water-filled quarry utilizing draglines. The excavated limestone is transported and processed by the customer. The following mines were operational during 2021:

Location Name

Aggregate

Location

State

Customer

Year NACCO Started Operations

White Rock — North

Limestone

Miami

WRQ

1995

Krome

Limestone

Miami

Cemex

2003

Alico

Limestone

Ft. Myers

Cemex

2004

FEC

Limestone

Miami

Cemex

2005

SCL

Limestone

Miami

Cemex

2006

Card Sound

Limestone

Florida City

Cemex

2009

Central State Aggregates

Limestone

Zephyrhills

McDonald Group

2016

Mid Coast Aggregates

Limestone

Sumter County

McDonald Group

2016

West Florida Aggregates

Limestone

Hernando County

McDonald Group

2016

St. Catherine

Limestone

Sumter County

Cemex

2016

Center Hill

Limestone

Sumter County

Cemex

2016

Inglis

Limestone

Crystal River

Cemex

2016

Titan Corkscrew

Limestone

Ft. Myers

Titan America

2017

Palm Beach Aggregates

Limestone

Loxahatchee

Palm Beach Aggregates

2017

Perry

Limestone

Lamont

Martin Marietta

2018

SDI Aggregates

Limestone

Florida City

Blue Water Industries

2018

Queensfield

Sand and gravel

King William County

King William Sand and Gravel Company, Inc.

2018

County Line (a)

Limestone

Pasco County

K&M Pasco 130 Holdings, LLC

2019

Newberry

Limestone

Alachua County

Argos USA, LLC

2019

Titan Pennsuco

Limestone

Miami

Titan America

2020

Seven Diamonds

Limestone

Pasco County

Seven Diamonds, LLC

2021

Johnson County

Sand and gravel

Johnson County

Martin Marietta

2021

Little River

Sand and gravel

Ashdown

Lehigh Hanson

2021

Rosser

Sand and gravel

Ennis

Lehigh Hanson

2021

Brooksville Cement Plant

Limestone

Brooksville

Cemex

2021

(a) The County Line contract was terminated during the third quarter of 2021. NAMining mined 0.1 million and 0.2 million tons of limestone at this location during the 2021 and 2020 periods, respectively.

NAMining's customers control all of the limestone and sand reserves within their respective mines. NAMining has no title, claim, lease or option to acquire any of the reserves at any of the mines where it provides services.

Access to the White Rock mine is by means of a paved road from 122nd Avenue.

Access to the Krome mine is by means of a paved road from Krome Avenue.

Access to the Alico mine is by means of a paved road from Alico Road.

Access to the FEC mine is by means of a paved road from NW 118th Avenue.

Access to the SCL mine is by means of a paved road from NW 137th Avenue.

Access to the Card Sound mine is by means of a paved road from SW 408th Street.

Access to the Central State Aggregates mine is by means of a paved road from Yonkers Boulevard.

Access to the Mid Coast Aggregates mine is by means of a paved road from State Road 50.

Access to the West Florida Aggregates mine is by means of a paved road from Cortez Boulevard.

Access to the St. Catherine mine is by means of a paved road from County Road 673.

Access to the Center Hill mine is by means of a paved road from West Kings Highway.

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Access to the Inglis mine is by means of a paved road from Highway 19 South.

Access to the Titan Corkscrew mine is by means of a paved road from Corkscrew Road.

Access to the Palm Beach Aggregates mine is by means of a paved road from State Road 80.

Access to the Perry mine is by means of paved road from Nutall Rise Road.

Access to the SDI Aggregates mine is by means of paved road from SW 167th AVE.

Access to the Queensfield Mine is by means of paved road from Dabney's Mill Road (SR 604).

Access to the County Line mine is by means of paved road from 18744 County Line Road.

Access to the Newberry mine is by means of paved road from NW County Road 235 (CR 235).

Access to the Titan Pennsuco mine is by means of a paved road from NW 121st Way.

Access to the Seven Diamonds mine is by means of a paved road from US-41 S/Broad St.

Access to the Johnson County mine is by means of a paved road from Old State 37/N Waverly Park Road.

Access to the Little River mine is by means of an unpaved road from Little River 60.

Access to the Rosser mine is by means of a paved road from TX-34 S.

Access to Brooksville Cement plant is by means of a paved road from Cement Plant Road.

Minerals Management - Operations

As an owner of royalty and mineral interests, the Company’s access to information concerning activity and operations of its royalty and mineral interests is limited. The Company does not have information that would be available to a company with oil and natural gas operations because detailed information is not generally available to owners of royalty and mineral interests. Consequently, the exact number of wells producing from or drilling on the Company’s mineral interests at a given point in time is not determinable. The following table sets forth the Company’s estimate of the number of gross and net productive wells as of December 31, 2021:


	Gross	Net
Oil	467	0.9
Natural Gas	398	11.4
Total	865	12.3

Gross wells are the total wells in which an interest is owned.

Net wells are calculated based on the Company's net royalty interest, factoring in both ownership percentage of gross wells and royalty rate.

The majority of the Company’s producing mineral and royalty interest acreage now, or in the future, can be pooled with third-party acreage to form pooled units. Pooling proportionately reduces the Company’s royalty interest in wells drilled in a pooled unit, and it proportionately increases the number of wells in which the Company has such reduced royalty interest.

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The following table includes the Company's estimate of acreage for oil and gas mineral interests, NPRIs, and ORRIs as of December 31, 2021:


	Gross Acres	Net Royalty Acres
Appalachia	34,661	36,199
East Texas/Haynesville	6,477	7,455
Permian	63,998	1,243
Eagle Ford	15,510	1,712
Other	7,139	13,327
Total	127,785	59,936

The Company may own more than one type of interest in the same tract of land, but the overlap is not significant. Net Royalty Acres are calculated based on the Company’s ownership and royalty rate, normalized to a standard 1/8th royalty lease, and assumes a 1/4th royalty rate for unleased acres.

The following table includes the Company's estimate of developed and undeveloped acreage based on the gross acres in a basin or region and includes mineral interests, NPRIs, and ORRIs as of December 31, 2021:


	Developed Acreage	Undeveloped Acreage	Gross Acreage
Appalachia	28,011	6,650	34,661
East Texas/Haynesville	5,253	1,224	6,477
Permian	62,496	1,503	63,998
Eagle Ford	15,510	0	15,510
Other	1,021	6,118	7,139
Total	112,291	15,495	127,785

Undeveloped acres are either unleased and open or are leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

Production and Price History

The following table sets forth the estimated oil and natural gas production data related to the Company’s mineral and royalty interests as well as certain price and cost information for the years ended December 31:


	2021 (4)		2020
Production data:
Oil (bbl) (1)	32,627		2,239
NGL (bbl) (1)	63,559		68,599
Residue gas (Mcf) (2)	6,225,422		7,981,545
Total BOE (3)	1,133,756		1,401,095
Average realized prices:
Oil (bbl) (1)	$	66.87	$	36.27
NGL (bbl) (1)	$	29.33	$	14.56
Residue gas (Mcf) (2)	$	3.36	$	1.87
Average unit cost
BOE (3)	$	4.99	$	6.01

(1) Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

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(2) Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

(3) BOE. Barrel of Oil Equivalent, a conversion factor of 6 MCF of gas was used for 1 equivalent bbl of oil.

(4) As an owner of mineral and royalty interests, the Company’s access to information concerning activity and operations of its royalty and mineral interests is limited. As a result, the Company estimated the last two months of 2021 production and pricing data using projections based on decline rates of wells and prior expense information.

Evaluation and Review of Reserves

The reserves estimates as of December 31, 2021 were prepared by Haas Petroleum Engineering Services, Inc. ("Haas Engineering"). Haas Engineering has provided reservoir engineering services, consulting and ongoing support for major and independent petroleum companies, public utilities, financial institutions, investors, and government agencies since 1980. Haas Engineering does not own an interest in NACCO or any of the Company's properties, nor is it employed on a contingent basis. A copy of Haas Engineering's estimated proved reserve report as of December 31, 2021 is incorporated by reference herein to Exhibit 99.1 to this Form 10-K.

The properties evaluated are located in Alabama, Louisiana, Ohio, Pennsylvania, and Texas and represent all of the Company’s oil and gas reserves. A reserves audit is not the same as a financial audit. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on several variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs.

The reserves estimates have been prepared using standard engineering practices generally accepted by the petroleum industry. Decline curve analysis was used to estimate the remaining reserves of pressure depletion reservoirs with enough historical production data to establish decline trends. Reservoirs under non-pressure depletion drive mechanisms and non-producing reserves were estimated by volumetric analysis, research of analogous reservoirs, or a combination of both. Reserves have been estimated using deterministic and probabilistic methods. The appropriate methodology was used, as deemed necessary, to estimate reserves in conformance with SEC regulations. The maximum remaining reserves life assigned to wells included in this report is 50 years.

Total net proved reserves are defined as those natural gas and hydrocarbon liquid reserves to the Company's interests after deducting all royalties, overriding royalties, and reversionary interests owned by outside parties that become effective upon payout of specified monetary balances. All reserves estimates have been prepared using standard engineering practices generally accepted by the petroleum industry and conform to guidelines developed and adopted by the SEC.

Technologies Used in Reserve Estimation

The SEC’s reserves rules allow the use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and/or NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Company employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of the Company’s proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the estimates of the Company’s reserves is a function of:

•the quality and quantity of available data and the engineering and geological interpretation of that data;

•estimates regarding the amount and timing of future operating costs, development costs and workovers, all of which may vary considerably from actual results;

•future prices of oil, natural gas and NGLs, which may vary considerably from those estimated; and

•the judgment of the persons preparing the estimates.

Table of Contents

The following table presents the Company's estimated net proved oil and natural gas reserves as of December 31, 2021 based on the reserve report prepared by Haas Engineering, the Company’s independent petroleum engineering firm. All of the Company’s reserves are located in the United States.


	Net reserves as of December 31, 2021
	Oil (bbl) (1)	NGL (bbl) (1)	Residue gas (Mcf) (2)
Proved developed	167,430	282,230	16,617,360
Proved undeveloped	220	90	1,210
Total	167,650	282,320	16,618,570

(1) Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

(2) Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

As an owner of mineral and royalty interests and not working interests, the Company is not required to make capital expenditures and did not make capital expenditures to convert proved undeveloped reserves from undeveloped to developed.

Internal Control Disclosure

The Company's internal staff works closely with Haas Engineering to ensure the integrity, accuracy and timeliness of the data used to calculate proved reserves relating to NACCO's assets. Internal technical team members met with independent reserve engineers periodically during the period covered by the reserves report to discuss the assumptions and methods used in the proved reserve estimation process.

The preparation of the Company's proved reserve estimates are completed in accordance with internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

•Review and verification of historical production data, which data is based on actual production as reported by third-party producers who lease the Company’s royalty and mineral interests;

•Preparation of reserve estimates by Haas Engineering under the direct supervision of internal staff;

•Review by the President of Catapult Mineral Partners of all of the Company's reported proved reserves at the close of each quarter, including the review of all significant reserve changes;

•Verification of property ownership by the Company's land department; and

•No employee’s compensation is tied to the amount of reserves booked.

The Minerals Management Segment’s Business Operations Manager is the technical person primarily responsible for overseeing the preparation of the internal reserve estimates and for coordinating with Haas Engineering in the preparation of the third-party reserve report. The Business Operations Manager has over 10 years of industry experience with positions of increasing responsibility and reports directly to the President of Catapult Mineral Partners, the Company’s business unit focused on managing and expanding the Company’s portfolio of oil and gas mineral and royalty interests.

Headquarter locations

NACCO leases office space in Mayfield Heights, Ohio, a suburb of Cleveland, Ohio, which serves as its corporate headquarters.

Coal Mining and Minerals Management lease corporate headquarters office space in Plano, Texas.

NAMining leases office and warehouse space in Medley, Florida.

Item 3. LEGAL PROCEEDINGS

Neither the Company nor any of its subsidiaries is a party to any material legal proceeding other than ordinary routine litigation incidental to its respective business.

Item 4. MINE SAFETY DISCLOSURES

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of The Dodd-Frank Act and Item 104 of Regulation S-K is included in Exhibit 95 filed with this Form 10-K.

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PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

NACCO's Class A common stock is traded on the New York Stock Exchange under the ticker symbol “NC.” Because of transfer restrictions, no trading market has developed, or is expected to develop, for the Company's Class B common stock. The Class B common stock is convertible into Class A common stock on a one-for-one basis.

At December 31, 2021, there were 691 Class A common stockholders of record and 126 Class B common stockholders of record.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers


Issuer Purchases of Equity Securities (1)
Period	(a) Total Number of Shares Purchased	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of the Publicly Announced Program	(d) Maximum Number of Shares (or Approximate Dollar Value) that May Yet Be Purchased Under the Program (1)
October 1 to 31, 2021	—	$	—	—	$	22,659,516
November 1 to 30, 2021	—	$	—	—	$	22,659,516
December 1 to 31, 2021	—	$	—	—	$	22,659,516
Total	—	$	—	—	$	22,659,516

(1) On November 10, 2021, the Company's Board of Directors approved a stock purchase program ("2021 Stock Repurchase Program") providing for the purchase of up to $20.0 million of the Company’s outstanding Class A common stock through December 31, 2023. See Note 12 to the Consolidated Financial Statements in this Form 10-K for a discussion of the Company's stock repurchase programs.

Item 6. SELECTED FINANCIAL DATA

As a “smaller reporting company” as defined by Rule 12b-2 of the Securities Exchange Act of 1934, the Company is not required to provide this information.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

OVERVIEW

Management's Discussion and Analysis of Financial Condition and Results of Operations contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are based upon management's current expectations and are subject to various uncertainties and changes in circumstances. Important factors that could cause actual results to differ materially from those described in these forward-looking statements are set forth below under the heading “Forward-Looking Statements."

Management's Discussion and Analysis of Financial Condition and Results of Operations include NACCO Industries, Inc.® (“NACCO” or the “Company”). NACCO brings natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through its robust portfolio of NACCO Natural Resources businesses. The Company operates under three business segments: Coal Mining, North American Mining ("NAMining") and Minerals Management. The Coal Mining segment operates surface coal mines for power generation companies and an activated carbon producer. The NAMining segment is a trusted mining partner for producers of aggregates, lithium and other minerals. The Minerals Management segment, which includes the Catapult Mineral Partners (“Catapult”) business, acquires and promotes the development of mineral interests. In addition, Mitigation Resources of North America® (“Mitigation Resources”) provides stream and wetland mitigation solutions.

All financial statement line items below operating profit (other income, including interest expense and interest income, the provision for income taxes and net income) are presented and discussed within this Form 10-K on a consolidated basis.

See “Item 1. Business" beginning on page 1 in this Form 10-K for further discussion of NACCO's subsidiaries. Additional information relating to financial and operating data on a segment basis (including unallocated items) is set forth in Note 15 to the Consolidated Financial Statements contained in this Form 10-K.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The Company's discussion and analysis of its financial condition and results of operations are based upon the Company's consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities (if any). On an ongoing basis, the Company evaluates its estimates based on historical experience, actuarial valuations and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from those estimates.

The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of its consolidated financial statements.

Revenue recognition: Revenues are recognized when control of the promised goods or services is transferred to the Company’s customers, in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The Company accounts for revenue in accordance with Accounting Standards Codification ("ASC") Topic 606, "Revenue from Contracts with Customers." See Note 3 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's revenue recognition.

Long-lived assets: The Company periodically evaluates long-lived assets for impairment when changes in circumstances or the occurrence of certain events indicate the carrying amount of an asset may not be recoverable. Upon identification of indicators of impairment, the Company evaluates the carrying value of the asset by comparing the estimated future undiscounted cash flows generated from the use of the asset and its eventual disposition with the asset's net carrying value. If the carrying value of an asset is considered impaired, an impairment charge is recorded for the amount that the carrying value

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

of the long-lived asset exceeds its fair value. Fair value is estimated as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

The Company regularly performs reviews of potential future development projects and identified certain undeveloped properties where market conditions related to any future development deteriorated during 2020. As a result, the Company recognized charges of $7.3 million in the Minerals Management segment and $1.1 million in the Coal Mining segment to write-off certain capitalized leasehold costs, prepaid royalties and other assets during 2020.

At MLMC, the costs of mining operations are not reimbursed by MLMC's customer. As such, increased costs at MLMC or decreased revenues could materially reduce the Company's profitability. Any reduction in customer demand at MLMC, including reductions related to reduced mechanical availability of the customer’s power plant, would adversely affect the Company's operating results and could result in significant impairments. MLMC has approximately $136 million of long-lived assets, including property, plant and equipment and its coal supply agreement intangible asset, which are subject to periodic impairment analysis and review. Identifying and assessing whether impairment indicators exist, or if events or changes in circumstances have occurred, including assumptions about future power plant dispatch levels, changes in operating costs and other factors that impact anticipated revenue and customer demand, requires significant judgment. Actual future operating results could differ significantly from these estimates, which may result in an impairment charge in a future period, which could have a substantial impact on the Company’s results of operations.

Income taxes: Tax law requires certain items to be included in the tax return at different times than the items are reflected in the financial statements. Some of these differences are permanent, such as expenses that are not deductible for tax purposes, and some differences are temporary, reversing over time, such as depreciation expense. These temporary differences create deferred tax assets and liabilities using currently enacted tax rates. The objective of accounting for income taxes is to recognize the amount of taxes payable or refundable for the current year, and deferred tax liabilities and assets for the future tax consequences of events that have been recognized in the financial statements or tax returns. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the provision for income taxes in the period that includes the enactment date. Management is required to estimate the timing of the recognition of deferred tax assets and liabilities, make assumptions about the future deductibility of deferred tax assets and assess deferred tax liabilities based on enacted laws and tax rates for the appropriate tax jurisdictions to determine the amount of such deferred tax assets and liabilities. Changes in the calculated deferred tax assets and liabilities may occur in certain circumstances, including statutory income tax rate changes, statutory tax law changes, or changes in the structure or tax status.

The Company's tax assets, liabilities, and tax expense are supported by historical earnings and losses and the Company's best estimates and assumptions of future earnings. The Company assesses whether a valuation allowance should be established against its deferred tax assets based on consideration of all available evidence, both positive and negative, using a more likely than not standard. This assessment considers, among other matters, scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations. The assumptions about future taxable income require significant judgment and are consistent with the plans and estimates the Company is using to manage the underlying businesses. When the Company determines, based on all available evidence, that it is more likely than not that deferred tax assets will not be realized, a valuation allowance is established.

Since significant judgment is required to assess the future tax consequences of events that have been recognized in the Company's financial statements or tax returns, the ultimate resolution of these events could result in adjustments to the Company's financial statements and such adjustments could be material. The Company believes the current assumptions, judgments and other considerations used to estimate the current year accrued and deferred tax positions are appropriate. If the actual outcome of future tax consequences differs from these estimates and assumptions, due to changes or future events, the resulting change to the provision for income taxes could have a material impact on the Company's results of operations and financial position.

See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's income taxes.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

CONSOLIDATED FINANCIAL SUMMARY

The results of operations for NACCO were as follows for the years ended December 31:


	2021			2020
Revenues:
Coal Mining	$	91,851		$	72,088
NAMining	69,924			42,392
Minerals Management	31,003			14,721
Unallocated Items	4,695			2,133
Eliminations	(5,627)			(2,902)
Total revenue	$	191,846		$	128,432
Operating profit (loss):
Coal Mining	$	49,059		$	25,436
NAMining	109			1,872
Minerals Management	26,080			3,493
Unallocated Items	(19,553)			(17,256)
Eliminations	(285)			(97)
Total operating profit	$	55,410		$	13,448
Interest expense	1,719			1,354
Interest income	(449)			(1,200)
Closed mine obligations	1,297			1,641
Gain on equity securities	(3,423)			(1,226)
Other, net	(584)			(1,379)
Other income, net	(1,440)			(810)
Income before income tax provision (benefit)	56,850			14,258
Income tax provision (benefit)	8,725			(535)
Net income	$	48,125		$	14,793

Effective income tax rate	15.3		%	(3.8)		%

The components of the change in revenues and operating profit are discussed below in "Segment Results."

Other income, net

Interest income decreased $0.8 million primarily due lower interest rates and a lower average invested cash balance during 2021 compared with 2020.

Gain on equity securities represents changes in the market price of invested assets reported at fair value. The change in 2021 compared with 2020 was due to fluctuations in the market prices of the underlying assets. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's invested assets reported at fair value.

North American Coal Corporation India Private Limited ("NACC India") was formed to provide technical business advisory

services to the third-party owner of a coal mine in India. During 2014, NACC India's customer defaulted on its contractual

payment obligations and as a result of this default, NACC India terminated its contract with the customer and began pursuing

contractual remedies. During 2020, the Company received a $1.0 million payment from NACC India's customer which has been reported on the line, Other, net.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

Income Taxes

The Company recorded an income tax expense of $8.7 million for the year ended December 31, 2021 on income before income tax of $56.9 million, or 15.3%, compared to income tax benefit of $0.5 million for the year ended December 31, 2020 on income before income tax of $14.3 million, or (3.8%). The income tax benefit for the year ended December 31, 2020 included $7.3 million of discrete tax charges primarily related to settlement of tax examinations, reserves for uncertain tax positions and return to provision adjustments partially offset by a benefit of $4.7 million, primarily due to the rate differential related to carrying back losses under the provisions of the Coronavirus Aid, Relief, and Economic Security Act ("CARES Act"). The CARES Act allows net operating tax losses incurred in 2018, 2019, and 2020 to be carried back to each of the five preceding taxable years to generate a refund of previously paid income taxes. The Company generated a net tax operating loss in 2020 primarily due to the realization of certain deferred tax assets. There were no material discrete items affecting income tax expense in 2021.

The effective income tax rate for 2021 reflects the impact of higher pre-tax income in 2021 compared with 2020, including the termination fee associated with the Bisti contract termination. The effective income tax rate varies based upon the mix and timing of earnings between entities that benefit from percentage depletion and those that do not benefit from percentage depletion. The benefit from percentage depletion is not directly related to the amount of pre-tax income recorded in a period.

See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's income taxes.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following tables detail the change in cash flow for the years ended December 31:


	2021		2020		Change
Operating activities:
Net income	$	48,125	$	14,793	$	33,332
Depreciation, depletion and amortization	23,085		18,114		4,971
Deferred income taxes	(3,553)		7,517		(11,070)
Stock-based compensation	5,561		3,078		2,483
Gain on sale of assets	(60)		(269)		209
Inventory impairment charge	—		1,973		(1,973)
Other asset impairment charge	—		8,359		(8,359)
Other	1,973		(3,452)		5,425
Working capital changes	(256)		(52,599)		52,343
Net cash provided by (used for) operating activities	74,875		(2,486)		77,361

Investing activities:
Expenditures for property, plant and equipment and acquisition of mineral interests	(44,561)		(44,368)		(193)
Proceeds from the sale of assets	633		571		62
Other	(219)		(2,187)		1,968
Net cash used for investing activities	(44,147)		(45,984)		1,837

Cash flow before financing activities	$	30,728	$	(48,470)	$	79,198

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

The $77.4 million increase in net cash provided by (used for) operating activities was primarily the result of favorable working capital changes and an increase in net income. Working capital changes primarily included:

•Decreased payments made under deferred compensation and long-term incentive compensation plans in 2021 compared with 2020.

•An increase in Accounts payable during 2021 compared with a decrease in Accounts payable during 2020 due to timing of payments.


	2021		2020		Change
Financing activities:
Net (reductions) additions to long-term debt and revolving credit agreements	$	(25,801)	$	20,073	$	(45,874)
Cash dividends paid	(5,617)		(5,375)		(242)
Other	(1,755)		(670)		(1,085)
Net cash (used for) provided by financing activities	$	(33,173)	$	14,028	$	(47,201)

The change in net cash (used for) provided by financing activities was primarily due to repayments during 2021 compared with borrowings during 2020.

Financing Activities

Financing arrangements are obtained and maintained at the subsidiary level. NACoal has a secured revolving line of credit of up to $150.0 million (the “NACoal Facility”) that expires in November 2025. Borrowings outstanding under the NACoal Facility were $4.0 million at December 31, 2021. At December 31, 2021, the excess availability under the NACoal Facility was $116.2 million, which reflects a reduction for outstanding letters of credit of $29.8 million.

NACCO has not guaranteed any borrowings of NACoal. The borrowing agreements at NACoal allow for the payment to NACCO of dividends and advances under certain circumstances. Dividends (to the extent permitted by NACoal's borrowing agreement) and management fees are the primary sources of cash for NACCO and enable the Company to pay dividends to stockholders.

The NACoal Facility has performance-based pricing, which sets interest rates based upon NACoal achieving various levels of debt to EBITDA ratios, as defined in the NACoal Facility. Borrowings bear interest at a floating rate plus a margin based on the level of debt to EBITDA ratio achieved. The applicable margins, effective December 31, 2021, for base rate and LIBOR loans were 1.25% and 2.25%, respectively. The NACoal Facility has a commitment fee which is based upon achieving various levels of debt to EBITDA ratios. The commitment fee was 0.35% on the unused commitment at December 31, 2021. During the year ended December 31, 2021, the average borrowing under the NACoal Facility was $20.5 million and the weighted-average annual interest rate was 2.1%.

EBITDA ratio of 1.50 to 1.00, or if greater than 1.50 to 1.00, a Fixed Charge Coverage Ratio of 1.10 to 1.00, in conjunction with maintaining unused availability thresholds of borrowing capacity, as defined in the NACoal Facility, of $15.0 million. At December 31, 2021, NACoal was in compliance with all financial covenants in the NACoal Facility.

The obligations under the NACoal Facility are guaranteed by certain of NACoal's direct and indirect, existing and future

domestic subsidiaries, and is secured by certain assets of NACoal and the guarantors, subject to customary exceptions and

limitations.

The Company believes funds available from cash on hand, the NACoal Facility and operating cash flows will provide sufficient liquidity to meet its operating needs and commitments arising during the next twelve months and until the expiration of the NACoal Facility in November 2025.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

Expenditures for property, plant and equipment and mineral interests

Following is a table which summarizes actual and planned expenditures (in millions):


	Planned		Actual		Actual
	2022		2021		2020
NACCO	$	68.0	$	44.6	$	44.4

Planned expenditures for 2022 are expected to be approximately $27 million in the NAMining segment, $22 million in the Coal Mining segment, $10 million in the Minerals Management segment and up to $9 million at Mitigation Resources.

In the Coal Mining segment, elevated levels of expected capital expenditures through 2022 are primarily related to spending at

MLMC as it develops a new mine area. In the NAMining segment, expected capital expenditures through 2022 are primarily

for the acquisition, relocation and refurbishment of draglines as well as the acquisition of other mining equipment to support the expansion of contract mining services beyond NAMining's historical dragline-oriented model, including the acquisition of

equipment to support Thacker Pass.

Expenditures are expected to be funded from internally generated funds and/or bank borrowings.

Capital Structure

NACCO's consolidated capital structure is presented below:


	December 31
	2021			2020			Change
Cash and cash equivalents	$	86,005		$	88,450		$	(2,445)
Other net tangible assets	276,733			244,907			31,826
Intangible assets, net	31,774			35,330			(3,556)
Net assets	394,512			368,687			25,825
Total debt	(20,710)			(46,465)			25,755
Closed mine obligations	(21,686)			(21,598)			(88)
Total equity	$	352,116		$	300,624		$	51,492
Debt to total capitalization	6		%	13		%	(7)		%

The increase in other net tangible assets was primarily due to an increase in Property, plant and equipment including mineral interests and Other non-current assets at December 31, 2021 compared with December 31, 2020. The increase in Other non-current assets is primarily due to an increase in pension assets and deferred financing fees as well as an increase in the market price of invested assets reported at fair value.

Contractual Obligations, Contingent Liabilities and Commitments

Pension and postretirement funding can vary significantly each year due to plan amendments, changes in the market value of plan assets, legislation and the Company’s decisions to contribute above the minimum regulatory funding requirements. The Company does not expect to contribute to its pension plan in 2022. NACCO maintains one supplemental retirement plan that pays monthly benefits to participants directly out of corporate funds and expects to pay benefits of approximately $0.5 million per year from 2022 through 2031. Benefit payments beyond that time cannot currently be estimated. NACCO also expects to make payments related to its other postretirement plans of approximately $0.2 million per year from 2022 through 2031. Benefit payments beyond that time cannot currently be estimated. All other pension benefit payments are made from assets of the pension plan.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

NACCO has asset retirement obligations. See Note 7 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's asset retirement obligations.

NACCO has leases. See Note 10 to the Consolidated Financial Statements in this Form 10-K for further information on the Company's leases.

NACCO has unrecognized tax benefits, including interest and penalties. See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's income taxes.

NACoal is a party to certain guarantees related to Coyote Creek. The Company believes that the likelihood of NACoal’s future performance under the guarantees is remote, and no amounts related to these guarantees have been recorded. See Note 17 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's guarantees.

The Company utilizes letters of credit to support commitments made in the ordinary course of business. As of December 31, 2021 and 2020, outstanding letters of credit totaled $29.8 million and $3.0 million, respectively. The increase in outstanding letters of credit in 2021 is primarily due to the issuance of $20.0 million letters of credit to collateralize a portion of outstanding surety bonds used to guarantee performance of consolidated mine reclamation obligations.

ENVIRONMENTAL MATTERS

The Company is affected by the regulations of numerous agencies, particularly the Federal Office of Surface Mining, the U.S. Environmental Protection Agency, the U.S. Army Corps of Engineers and associated state regulatory authorities. In addition, the Company closely monitors proposed legislation and regulation concerning SMCRA, CAA, ACE, CWA, RCRA, CERCLA and other regulatory actions.

Compliance with these increasingly stringent regulations could result in higher expenditures for both capital improvements and operating costs. The Company’s policies stress environmental responsibility and compliance with these regulations. Based on current information, management does not expect compliance with these regulations to have a material adverse effect on the Company’s financial condition or results of operations. See Item 1 in Part I of this Form 10-K for further discussion of these matters.

SEGMENT RESULTS

COAL MINING SEGMENT

FINANCIAL REVIEW

See “Item 2. Properties" on page 31 in this Form 10-K for discussion of the Company's mineral resources and mineral reserves.

Tons of coal delivered by the Coal Mining segment were as follows for the years ended December 31:


	2021	2020







Unconsolidated mines	28,052	28,486

Consolidated mines	3,025	2,538
Total tons delivered	31,077	31,024

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

The results of operations for the Coal Mining segment were as follows for the years ended December 31:


	2021		2020
Revenues	$	91,851	$	72,088
Cost of sales	79,167		70,452
Gross profit	12,684		1,636
Earnings of unconsolidated operations(a)	56,982		56,584
Contract termination settlement	10,333		—
Selling, general and administrative expenses	27,363		30,216
Amortization of intangible assets	3,556		2,572
Loss (gain) on sale of assets	21		(4)
Operating profit	$	49,059	$	25,436

(a) See Note 17 to the Consolidated Financial Statements in this Form 10-K for a discussion of the Company's unconsolidated subsidiaries, including summarized financial information.

2021 Compared with 2020

Revenues increased 27.4% in 2021 compared with 2020 primarily due to an increase in customer demand and tons delivered at MLMC. Also contributing to the change was the recognition of reclamation revenue from Caddo Creek. During the fourth quarter of 2020, Caddo Creek entered into a contract with a subsidiary of Advanced Emissions Solutions to perform mine reclamation. As a result of these changes, Caddo Creek financial results are consolidated within the Coal Mining segment.

The following table identifies the components of change in operating profit for 2021 compared with 2020:


	Operating Profit
2020	$	25,436
Increase (decrease) from:
Contract termination settlement	10,333
Gross profit, excluding MLMC's 2020 inventory impairment charge	9,075
MLMC 's inventory impairment charge during 2020	1,973
Voluntary separation program ("VSP") charge during 2020	1,475
Selling, general and administrative expenses, excluding VSP charge	1,378
Earnings of unconsolidated operations	398
Amortization of intangibles	(984)
Net change on sale of assets	(25)
2021	$	49,059

Operating profit increased $23.6 million in 2021 compared with 2020. The change in operating profit was primarily due to:

•The $10.3 million payment recognized during 2021 related to the Bisti contract termination.

•An increase in gross profit due to an increase in the profit per ton delivered at MLMC and earnings associated with the reclamation contract at Caddo Creek. In addition, 2020 included certain costs associated with the termination of the Camino Real Fuels, LLC contract mining agreement and higher outside service expenses at Centennial Natural Resources.

•The following items recognized in the prior year did not recur in 2021:

◦A $2.0 million inventory impairment charge at MLMC as mining costs exceeded net realizable value.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

◦A charge of $1.5 million related to one-time termination benefits as a result of a voluntary separation program for employees who met certain age and service requirements to reduce overall headcount.

◦A $1.1 million asset impairment charge included in selling, general and administrative expenses in the table above.

•In addition, selling, general and administrative expenses in 2021 include a decrease in employee-related costs and professional service expenses, both partially offset by higher insurance expense. Included in insurance expense is an increase of $1.3 million that is reimbursed by one of the Unconsolidated Subsidiaries. The offsetting income related to the reimbursement is included in Earnings of unconsolidated operations.

NORTH AMERICAN MINING ("NAMining") SEGMENT

FINANCIAL REVIEW

Aggregate tons delivered by the NAMining segment were as follows for the years ended December 31:


	2021	2020
Unconsolidated operations	9,938	9,367
Consolidated operations	42,565	36,546
Total tons delivered	52,503	45,913

The results of operations for the NAMining segment were as follows for the years ended December 31:


	2021		2020
Total revenues	$	69,924	$	42,392
Reimbursable costs	51,028		26,893
Revenues excluding reimbursable costs	$	18,896	$	15,499

Revenues	$	69,924	$	42,392
Cost of sales	67,078		39,266
Gross profit	2,846		3,126
Earnings of unconsolidated operations(a)	3,861		3,619
Selling, general and administrative expenses	6,610		5,138
Gain on sale of assets	(12)		(265)
Operating profit	$	109	$	1,872

(a) See Note 17 to the Consolidated Financial Statements in this Form 10-K for a discussion of the Company's unconsolidated subsidiaries, including summarized financial information.

2021 Compared with 2020

Total revenues increased 64.9% in 2021 compared with 2020 primarily due to a $24.1 million increase in reimbursable costs, which have an offsetting amount in cost of sales and have no impact on operating profit. The relocation of draglines related to new and amended contracts is the main driver of the increase in reimbursable costs. The increase in revenues excluding reimbursable costs is primarily due to an increase in customer demand and tons delivered.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

The following table identifies the components of change in operating profit for 2021 compared with 2020.


	Operating Profit
2020	$	1,872
Increase (decrease) from:
Selling, general and administrative expenses	(1,472)
Gross profit	(280)
Net change on sale of assets	(253)
Earnings of unconsolidated operations	242
2021	$	109

Operating profit decreased $1.8 million in 2021 compared with 2020 primarily due to an increase in selling, general and administrative expenses, mainly attributable to higher employee-related costs, which include an increase in business development expenses.

MINERALS MANAGEMENT SEGMENT

FINANCIAL REVIEW

The results of operations for the Minerals Management segment were as follows for the years ended December 31:


	2021		2020
Revenues	$	31,003	$	14,721
Cost of sales	2,988		2,342
Gross profit	28,015		12,379
Selling, general and administrative expenses	2,004		8,886
Gain on sale of assets	(69)		—
Operating profit	$	26,080	$	3,493

2021 Compared with 2020

Revenues and operating profit increased in 2021 compared with 2020 primarily due to royalty income generated by gas production from the Ohio and Louisiana mineral interests, as well as oil production from the Permian Basin and Eagle Ford Shale mineral interests acquired late in the fourth quarter of 2020 and early in the second quarter of 2021, respectively. Favorable changes in natural gas and oil prices also contributed to the improvement in revenues and operating profit. In addition, the Company recognized $3.6 million of settlement income during 2021.

The decrease in selling, general and administrative expenses is primarily due to the absence of a $7.3 million asset impairment charge recognized in 2020. The Company regularly performs reviews of potential future development projects and identified certain undeveloped properties where market conditions related to any future development deteriorated during 2020. As a result, the Company wrote-off certain capitalized leasehold costs and prepaid royalties related to legacy coal interests in 2020.

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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

UNALLOCATED ITEMS AND ELIMINATIONS

FINANCIAL REVIEW

Unallocated Items and Eliminations were as follows for the years ended December 31:


	2021		2020
Operating loss	$	(19,838)	$	(17,353)

2021 Compared with 2020

The operating loss increased during 2021 compared with 2020 primarily due to higher employee-related costs and an increase in expenses related to business development initiatives.

During the fourth quarter of 2020, the Company implemented a voluntary separation program for employees who met certain age and service requirements to reduce overall headcount. As a result of this program, the 2020 operating loss includes a charge of $0.3 million related to one-time termination benefits.

NACCO Industries, Inc. Outlook

Coal Mining Outlook

As previously announced, GRE entered into an agreement to sell Coal Creek Station and the adjacent high-voltage direct current transmission line to Bismarck, North Dakota-based Rainbow Energy. The closing of this sale is expected to occur in the second quarter of 2022. Upon completion of the sale of Coal Creek Station, the existing agreements between GRE and Falkirk will terminate. GRE will pay the Company $14.0 million, as well as transfer ownership of an office building and convey membership units in Midwest AgEnergy to wholly owned and consolidated subsidiaries of NACCO.

Upon closing of the sale to Rainbow Energy, a new Coal Sales Agreement ("CSA") between Falkirk and Rainbow Energy will become effective and Falkirk will continue supplying all coal requirements of Coal Creek Station. Falkirk will be paid a management fee per ton of coal delivered for operating the mine, and Rainbow Energy will be responsible for funding all mine operating costs and directly or indirectly providing all of the capital required to operate the mine. The CSA specifies that Falkirk will perform final mine reclamation, which will be funded in its entirety by Rainbow Energy. The initial production period is expected to run ten years from the effective date of the CSA, but the CSA may be extended or terminated early under certain circumstances.

Coal Mining operating profit in 2022 is expected to decrease significantly compared with 2021. This expected decrease is primarily the result of a decrease in coal deliveries from 2021 levels, as well as the termination of the Bisti contract. An anticipated increase in operating expenses primarily due to expected higher insurance costs and other professional fees is also expected to contribute to the reduction in operating profit.

Results at the consolidated mining operations are expected to decrease significantly in 2022 from 2021 primarily due to expected substantially lower earnings at MLMC driven by an anticipated reduction in customer demand from 2021 levels, which contributes to an increase in the cost per ton. Cost inflation on repairs, supplies and diesel fuel, and higher depreciation expense related to recent capital expenditures to develop a new mine area will also contribute to the increase in the cost per ton in 2022. In general, cost per ton delivered is lowest when the power plant requires a consistently high level of coal deliveries, primarily because costs are spread over more tons.

The reduction in earnings at the unconsolidated Coal Mining operations is expected to be mainly driven by lower earnings at Falkirk resulting in part from a planned power plant outage prior to the expected closure of the Rainbow Energy transaction. In addition, to support the transfer of Coal Creek Station, Falkirk has agreed to a reduction in the current per ton management fee from the effective date of the new CSA with Rainbow Energy through May 31, 2024. After May 31, 2024, Falkirk's per ton management fee increases to a higher base in line with current fee levels, and thereafter adjusts annually according to an index

Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

which tracks a broad measure of U.S. inflation. Termination of the Bisti contract in late 2021 will also contribute to a decline in the earnings at the unconsolidated mining operations in 2022.

Segment adjusted EBITDA, which excludes the termination payments of $10.3 million from Bisti's customer in 2021 and the anticipated $14 million contract termination fee from GRE in 2022, is expected to decrease significantly in 2022 from 2021 primarily as a result of the forecasted reduction in operating profit partially offset by an increase in depreciation, depletion and amortization expense. The increase in depreciation, depletion and amortization expense is primarily due to higher capital expenditures at MLMC as a result of the development of a new mine area.

Capital expenditures are expected to be approximately $22 million in 2022. The elevated levels of capital expenditures from 2019 through 2022 relate to the necessary development of a new mine area at MLMC, which will allow continued coal deliveries through the end of the contract. The increase in capital expenditures associated with mine development will result in higher depreciation expense in future periods that will unfavorably affect future operating profit. Capital expenditures for MLMC are expected to decline significantly beginning in 2023.

The Company's contract structure at each of its coal mining operations eliminates exposure to spot coal market price fluctuations. However, fluctuations in natural gas prices and the availability of renewable generation, particularly wind, can contribute to changes in power plant dispatch and customer demand for coal. The significant increase in natural gas prices in 2021 contributed to an increase in customer power plant dispatch and coal deliveries in 2021 over 2020. Sustained higher natural gas prices could lead to increased demand for coal and positively affect the Coal Mining segment results in 2022. Changes to expectations for customer power plant dispatch could affect the Company’s outlook for 2022 and over the longer term. The owner of the power plant served by the Company's Sabine Mine in Texas intends to retire the power plant in the first quarter of 2023, at which time Sabine expects to begin final reclamation. Funding for mine reclamation is the responsibility of the customer. Coteau operates the Freedom Mine in North Dakota. All coal production from the Freedom Mine is delivered to Basin Electric Power Cooperative. Basin Electric utilizes the coal at the Great Plains Synfuels Plant, Antelope Valley Station and Leland Olds Station. The Synfuels Plant is a coal gasification plant owned by Dakota Gas that manufactures synthetic natural gas and produces fertilizers, solvents, phenol, carbon dioxide and other chemical products for sale. In August 2021, Basin Electric announced that it signed a non-binding term sheet which contemplates the sale of the assets of Dakota Gas. As part of the announcement, Basin Electric indicated that the Synfuels Plant will continue existing operations through 2025. The closing is subject to the satisfaction of specified conditions. Basin Electric is also considering other options for the Synfuels Plant if the transaction with the potential buyer does not close.

NAMining Outlook

In 2022, NAMining expects full-year operating profit to increase significantly over 2021 due to an expected increase in customer requirements and contributions from contracts executed during 2021. Segment adjusted EBITDA for 2022 is expected to increase significantly compared with the prior year as a result of the improvement in operating profit and an increase in depreciation expense.

During 2021, NAMining expanded its geographic footprint by entering into new contract mining services agreements at quarries in Indiana, Texas and Arkansas. In addition, NAMining entered into a 15-year mining services contract with a new customer at a limestone quarry in Central Florida. Presently, NAMining is operating two smaller draglines at this quarry while it relocates a larger dragline that will significantly increase production capacity once commissioned, which is expected to occur in the second half of 2022. NAMining also amended a contract with a current customer to provide additional services at a limestone quarry in Florida. NAMining continues to have a substantial pipeline of potential new projects and is pursuing a number of growth initiatives that, if successful, would be accretive to future earnings.

In 2019, NAMining's subsidiary, Sawtooth Mining, LLC, entered into a mining services agreement to serve as the exclusive contract miner for the Thacker Pass lithium project in northern Nevada, owned by Lithium Nevada Corp., a subsidiary of Lithium Americas Corp. (TSX: LAC) (NYSE: LAC). Lithium Americas owns the lithium reserves at Thacker Pass and will be responsible for the processing and sale of the lithium produced. In January 2022, Lithium Americas provided an update on the Thacker Pass project, which noted that final permitting decisions are expected to be received in the first quarter of 2022. Early-works construction is expected to begin in 2022. At maturity, this management fee contract is expected to deliver fee income similar to a mid-sized management fee coal mine.

Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

In 2022, capital expenditures are expected to be approximately $27 million primarily for the acquisition, relocation and refurbishment of draglines, as well as the acquisition of other mining equipment to support the continued expansion of contract-mining services beyond NAMining's historical dragline-oriented model, including the acquisition of equipment to support the Thacker Pass lithium project. The cost of mining equipment related to Thacker Pass will be reimbursed by the customer over a seven-year period from the equipment acquisition date.

Minerals Management Outlook

The Minerals Management segment derives income from royalty-based leases under which lessees make payments to the Company based on their sale of natural gas, oil, natural gas liquids and coal, extracted primarily by third parties.

Operating profit and Segment adjusted EBITDA in 2022 are expected to decrease significantly from 2021 primarily driven by an anticipated reduction in production due to the natural decline curve on wells in Ohio, expectations for natural gas and oil prices, and the absence of $3.6 million of settlement income recognized in 2021. The Company expects oil and gas market prices to moderate in 2022 and stabilize at levels consistent with averages over the second half of 2021.

Natural gas and oil benchmark prices increased during 2021 when compared with historical periods. If natural gas and oil prices remain at higher levels than currently anticipated, results for the 2022 full year could be favorably impacted. Commodity prices are inherently volatile and as an owner of royalty and mineral interests, the Company’s access to information concerning activity and operations of its interests is limited. The Company's expectations are based on the best information currently available and could vary as a result of adjustments made by operators and/or changes to commodity prices.

The Company is in a period of transition where production from more recently acquired mineral interests is expected to begin to offset anticipated declines in production at legacy natural gas wells. This transition is expected to occur over the next few years as the Company’s portfolio of recently acquired mineral interests continues to expand. Minerals Management is targeting additional investments in mineral and royalty interests of approximately $10 million in 2022. These investments are expected to be accretive, but each investment's contribution to earnings is dependent on the details of that investment, including the size and type of interests acquired and the stage and timing of mineral development. The contribution of each investment could also vary due to commodity price changes. These acquired interests are expected to align with the Company’s strategy of selectively acquiring mineral and royalty interests with a balance of near-term cash-flow yields and long-term growth potential, in high-quality reservoirs offering diversification from the Company’s legacy mineral interests.

Consolidated Outlook

Overall, in 2022, NACCO expects consolidated net income and Consolidated Adjusted EBITDA to decrease significantly from 2021. Lower operating profit in the Coal Mining segment and an anticipated reduction in income in the Minerals Management segment are expected to be partially offset by higher operating profit at NAMining and lower income tax expense. Additionally, the Company expects to recognize the value of the North Dakota office building and the membership units in Midwest AgEnergy, which are expected to be received as part of the compensation from GRE upon the closing of the transaction with Rainbow Energy. Securing contracts for new mining projects and acquisitions of additional mineral interests could be accretive to the current forecast.

Consolidated capital expenditures are expected to be approximately $68 million in 2022. Capital expenditures in 2022 include approximately $9 million for expenditures at Mitigation Resources of North America®. As a result of the forecasted capital expenditures and anticipated decrease in net income, cash flow before financing activities is expected to return to a significant use of cash in 2022.

Growth and Diversification

Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

business. Each of these businesses continues to expand its pipeline of potential new projects with opportunities for growth and diversification.

NAMining is pursuing growth and diversification by expanding the scope of its business development activities to include potential customers who require a broad range of minerals and materials and by leveraging the Company’s core mining skills to expand the range of contract mining services it provides. NAMining advanced these efforts in 2021 when it entered into a contract to mine sand and gravel in Indiana and signed contracts to perform all mining operations at two sand and gravel quarries located in Texas and Arkansas. The new contracts in Texas and Arkansas include responsibility for all mining activities, including pre-strip, blasting, excavation and load and haul operations. These new contracts with leading suppliers of construction materials in North America expand the range of contract mining services beyond the traditional scope of NAMining's core, dragline-oriented limestone mining business and expand its geographic footprint beyond Florida. In addition, NAMining continues to pursue additional opportunities to provide comprehensive mining services to operate entire mines, as it expects to do at the new lithium project in Nevada. The goal is to build NAMining into a leading provider of contract mining services for customers that produce a wide variety of minerals and materials. The Company believes NAMining can grow to be a substantial contributor to operating profit, delivering unlevered after-tax returns on invested capital in the mid-teens as this business model matures and achieves significant scale, but the pace of growth will be dependent on the mix and scale of new projects.

The Minerals Management segment continues to grow and diversify by pursuing acquisitions of mineral and royalty interests in the United States, in a market environment that the Company believes remains well-aligned with its strategy and objectives. The Minerals Management segment will benefit from the continued development of its mineral properties without additional capital investment, as all further development costs are borne entirely by third-party producers who lease the minerals. This business model can deliver higher average operating margins over the life of a reserve than traditional oil and gas companies that bear the cost of exploration, production and/or development. Catapult, the Company’s business unit focused on managing and expanding the Company’s portfolio of oil and gas mineral and royalty interests, has developed a strong network to source and secure new acquisitions, and has several potential acquisitions under review. The goal is to construct a diversified portfolio of high-quality oil and gas mineral and royalty interests in the United States that deliver near-term cash flow yields and long-term projected growth. The Company believes this business will provide unlevered after-tax returns on invested capital in the low-to-mid-teens as the portfolio of reserves and mineral interests grows and this business model matures.

Mitigation Resources continues to expand its business, which creates and sells stream and wetland mitigation credits and provides services to those engaged in permittee-responsible mitigation. This business offers an opportunity for growth and diversification in an industry where the Company has substantial knowledge and expertise and a strong reputation. The Mitigation Resources business has achieved several early successes and is positioned for additional growth. The Company's goal is to grow Mitigation Resources into one of the ten largest U.S. providers of mitigation solutions, largely focused on streams and wetlands, initially in the southeast United States. While this business is in the early stages of development, it is currently focused on expanding and has established mitigation projects in Alabama, Mississippi, Texas and Tennessee. The Company believes that Mitigation Resources can provide solid rates of return as this business matures.

Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

The Company is committed to maintaining a conservative capital structure as it continues to grow and diversify, while avoiding unnecessary risk. Strategic diversification will generate cash that can be re-invested to strengthen and expand the businesses. The Company also continues to maintain the highest levels of customer service and operational excellence with an unwavering focus on safety and environmental stewardship.

RECENTLY ISSUED ACCOUNTING STANDARDS

See Note 2 to the Consolidated Financial Statements in this Form 10-K for a description of recently issued accounting standards, if any, including actual and expected dates of adoption and effects to the Company's Consolidated Financial Statements.

FORWARD-LOOKING STATEMENTS

The statements contained in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere throughout this Annual Report on Form 10-K that are not historical facts are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are made subject to certain risks and uncertainties, which could cause actual results to differ materially from those presented. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. The Company undertakes no obligation to publicly revise these forward-looking statements to reflect events or circumstances that arise after the date hereof. Among the factors that could cause plans, actions and results to differ materially from current expectations are, without limitation: (1) changes to or termination of customer or other third-party contracts, or a customer or other third party default under a contract, (2) Any customer's premature facility closure, including GRE’s failure to complete the sale of Coal Creek Station to Rainbow Energy, (3) a significant reduction in purchases by the Company's customers, including as a result of changes in coal consumption patterns of U.S. electric power generators, or changes in the power industry that would affect demand for the Company's coal and other mineral reserves, (4) failure to obtain adequate insurance coverages at reasonable rates, (5) the impact of the COVID-19 pandemic, including any impact on suppliers, customers and employees, (6) supply chain disruptions, including price increases and shortages of parts and materials, (7) changes in tax laws or regulatory requirements, including the elimination of, or reduction in, the percentage depletion tax deduction, changes in mining or power plant emission regulations and health, safety or environmental legislation, (8) the ability of the Company to access credit in the current economic environment, or obtain financing at reasonable rates, or at all, and to maintain surety bonds for mine reclamation as a result of current market sentiment for fossil fuels, (9) the effects of investors’ and other stakeholders’ increasing attention to environmental, social and governance (“ESG”) matters, (10) changes in costs related to geological and geotechnical conditions, repairs and maintenance, new equipment and replacement parts, fuel or other similar items, (11) regulatory actions, changes in mining permit requirements or delays in obtaining mining permits that could affect deliveries to customers, (12) weather conditions, extended power plant outages, liquidity events or other events that would change the level of customers' coal or aggregates requirements, (13) weather or equipment problems that could affect deliveries to customers, (14) failure or delays by the Company's lessees in achieving expected production of natural gas and other hydrocarbons; the availability and cost of transportation and processing services in the areas where the Company's oil and gas reserves are located; federal and state legislative and regulatory initiatives relating to hydraulic fracturing; and the ability of lessees to obtain capital or financing needed for well-development operations and leasing and development of oil and gas reserves on federal lands, (15) changes in the costs to reclaim mining areas, (16) costs to pursue and develop new mining, mitigation and oil and gas opportunities and other value-added service opportunities, (17) delays or reductions in coal or aggregates deliveries, (18) changes in the prices of hydrocarbons, particularly diesel fuel, natural gas and oil, (19) the ability to successfully evaluate investments and achieve intended financial results in new business and growth initiatives, (20) disruptions from natural or human causes, including severe weather, accidents, fires, earthquakes and terrorist acts, any of which could result in suspension of operations or harm to people or the environment, and (21) the ability to attract, retain, and replace workforce and administrative employees.

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Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

As a “smaller reporting company” as defined by Rule 12b-2 of the Securities Exchange Act of 1934, the Company is not required to provide this information.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by this Item 8 is set forth in the Financial Statements and Supplementary Data contained in Part IV of this Form 10-K and is hereby incorporated herein by reference to such information.

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

There were no disagreements with accountants on accounting and financial disclosure for the two-year period ended December 31, 2021 that require disclosure pursuant to this Item 9.

Item 9A. CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures: An evaluation was carried out under the supervision and with the participation of the Company's management, including the principal executive officer and the principal financial officer, of the effectiveness of the Company's disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, these officers have concluded that the Company's disclosure controls and procedures are effective.

Management's report on internal control over financial reporting: Management is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on this evaluation under the framework, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2021. The Company's effectiveness of internal control over financial reporting as of December 31, 2021 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in its report, which is included in Item 15 of this Form 10-K and incorporated herein by reference.

Changes in internal control: There have been no changes in the Company's internal control over financial reporting, that occurred during the fourth quarter of 2021, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

Item 9B. OTHER INFORMATION

None.

Item 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

None.

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PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information with respect to Directors of the Company will be set forth in the 2022 Proxy Statement under the subheadings “Part III — Proposals To Be Voted On At The 2022 Annual Meeting — Proposal 1 — Election of Directors,” which information is incorporated herein by reference.

Information with respect to the audit review committee and the audit review committee financial expert will be set forth in the 2022 Proxy Statement under the subheading “Part I — Corporate Governance Information — Directors' Meetings and Committees,” which information is incorporated herein by reference.

Information with respect to compliance with Section 16(a) of the Securities Exchange Act of 1934 by the Company's Directors, executive officers and holders of more than ten percent of the Company's equity securities will be set forth in the 2022 Proxy Statement under the subheading “Part IV — Other Important Information — Delinquent Section 16(a) Reports,” which information is incorporated herein by reference.

The Company has adopted a code of business conduct and ethics applicable to all Company personnel, including the principal executive officer, principal financial officer, principal accounting officer or controller, or other persons performing similar functions. The code of business conduct and ethics, entitled the “Code of Corporate Conduct,” is posted on the Company's website at www.nacco.com under “Corporate Governance.” If the Company makes any amendments to or grants any waivers from the code of business conduct and ethics which are required to be disclosed pursuant to the Securities and Exchange Act of 1934, the Company will make such disclosure on the NACCO website.

Item 11. EXECUTIVE COMPENSATION

Information with respect to executive compensation will be set forth in the 2022 Proxy Statement under the headings “Part II — Executive Compensation Information” and “Part III — Proposals To Be Voted On At The 2022 Annual Meeting — Proposal 1 — Election of Directors,” which information is incorporated herein by reference.

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information with respect to security ownership of certain beneficial owners and management will be set forth in the 2022 Proxy Statement under the subheading “Part IV — Other Important Information — Beneficial Ownership of Class A Common and Class B Common,” which information is incorporated herein by reference.

Information with respect to compensation plans (including individual compensation arrangements) under which equity securities are authorized for issuance will be set forth in the 2022 Proxy Statement under the subheading “Part IV — Other Important Information — Equity Compensation Plan Information," which information is incorporated herein by reference.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information with respect to certain relationships and related transactions will be set forth in the 2022 Proxy Statement under the subheadings “Part I — Corporate Governance Information — Review and Approval of Related-Person Transactions,” which information is incorporated herein by reference.

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information with respect to principal accountant fees and services will be set forth in the 2022 Proxy Statement under the heading “Part III — Proposals To Be Voted On At The 2022 Annual Meeting — Proposal 3 — Ratification of the Appointment of Company's Independent Registered Public Accounting Firm,” which information is incorporated herein by reference.

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PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) (1) and (2) The response to Item 15(a)(1) and (2) is set forth beginning at page F-1 of this Form 10-K.

(b) Financial Statement Schedules — The response to Item 15(c) is set forth beginning at page F-42 of this Form 10-K.


Exhibit Number						Exhibit Description
(3) Articles of Incorporation and By-laws.
3.1(i)						Restated Certificate of Incorporation of the Company is incorporated herein by reference to Exhibit 3(i) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File Number 1-9172.
3.1(ii)						Amended and Restated By-laws of the Company are incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, filed by the Company on December 18, 2014, Commission File Number 1-9172.

(4) Instruments defining the rights of security holders, including indentures.
4.1						The Company by this filing agrees, upon request, to file with the Securities and Exchange Commission the instruments defining the rights of holders of long-term debt of the Company and its subsidiaries where the total amount of securities authorized thereunder does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis.
4.2						The Mortgage and Security Agreement, dated April 8, 1976, between The Falkirk Mining Company (as Mortgagor) and Cooperative Power Association and United Power Association (collectively, as Mortgagee) is incorporated herein by reference to Exhibit 4(ii) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File Number 1-9172.
4.3						Amendment No. 1 to the Mortgage and Security Agreement, dated as of December 15, 1993, between Falkirk Mining Company (as Mortgagor) and Cooperative Power Association and United Power Association (collectively, as Mortgagee) is incorporated herein by reference to Exhibit 4(iii) to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, Commission File Number 1-9172.
4.4						Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, among NACCO Industries, Inc., the other signatories thereto and NACCO Industries, Inc., as depository, is incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K, filed by the Company on October 5, 2017, Commission File Number 1-9172.
4.5						Amendment to Amended and Restated Stockholders' Agreement, dated as of February 14, 2019, among NACCO Industries, Inc., the other signatories thereto and NACCO Industries, Inc., as depository, is incorporated by reference to Exhibit 4.5 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2018, Commission File Number 1-9172.
4.6						Second Amendment to Amended and Restated Stockholders' Agreement, dated as of February 12, 2021, by and among the Depository, NACCO Industries, Inc., the new Participating Stockholders identified on the signature pages thereto and the Participating Stockholders under the Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, as amended, is incorporated by reference to Exhibit 60 of the Company's General statement of acquisition of beneficial ownership on Form SC 13D, filed on February 12, 2021, Commission File Number 1-9172.
4.7						Third Amendment to Amended and Restated Stockholders' Agreement, dated as of February 11, 2022, by and among the Depository, NACCO Industries, Inc., the new Participating Stockholders identified on the signature pages thereto and the Participating Stockholders under the Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, as amended, is incorporated by reference to Exhibit 99.8 of the Company's General statement of acquisition of beneficial ownership on Form SC 13D, filed on February 11, 2022, Commission File Number 1-9172.
4.8						Description of Securities is incorporated herein by reference to Exhibit 4.6 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, Commission File Number 1-9172.

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Exhibit Number						Exhibit Description
(10) Material contracts
10.1*						NACCO Industries, Inc. Supplemental Executive Long-Term Incentive Bonus Plan (Amended and Restated March 1, 2012) is incorporated herein by reference to Appendix B to NACCO's Definitive Proxy Statement, filed by NACCO on March 16, 2012, Commission File Number 1-9172.
10.2*						NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan (Amended and Restated March 1, 2019) is incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed by the Company on May 8, 2019, Commission File Number 1-9172.
10.3*						NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan (Amended and Restated March 1, 20 21 ) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on May 19 , 20 21 , Commission File Number 1-9172.
10.4*						NACCO Industries, Inc. Non-Employee Directors' Equity Compensation Plan (Amended and Restated May 8, 2019) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on May 8, 2019, Commission File Number 1-9172.
10.5*						NACCO Industries, Inc. Non-Employee Directors' Equity Compensation Plan (Amended and Restated May 19 , 20 21 ) is incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed by the Company on May 19 , 20 21 , Commission File Number 1-9172.
10.6*						Form of Award Agreement for the NACCO Industries, Inc. Supplemental Executive Long-Term Incentive Bonus Plan is incorporated by reference to Exhibit 10.8 to the Company's Current Report on Form 8-K, filed by the Company on September 17, 2012, Commission File Number 1-9172.
10.7*						Form of Cashless Exercise Award Agreement for the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan is incorporated herein by reference to Exhibit 10.9 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, Commission File Number 1-9172.
10.8*						Form of Non-Cashless Exercise Award Agreement for the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan is incorporated herein by reference to Exhibit 10.10 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, Commission File Number 1-9172.
10.9						Separation Agreement, dated as of September 29, 2017, between NACCO Industries, Inc. and Hamilton Beach Brands Holding Company, is incorporated by reference to Exhibit 10.1 of Hamilton Beach Brands Holding Company's Current Report on Form 8-K, filed on October 4, 2017, Commission File Number 1-9172.
10.10						Tax Allocation Agreement, dated as of September 29, 2017, between NACCO Industries, Inc. and Hamilton Beach Brands Holding Company, is incorporated by reference to Exhibit 10.3 of Hamilton Beach Brands Holding Company's Current Report on Form 8-K, filed on October 4, 2017, Commission File Number 1-9172.
10.11						Consulting Agreement, dated as of September 29, 2017, between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.5 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on October 5, 2017, Commission File Number 1-9172.
10.12						Amendment to Consulting Agreement, dated as of December 15, 2020, between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.1 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on December 15, 2020, Commission File Number 1-9172.
10.13						Amendment to Consulting Agreement, dated as of December 21 , 202 1 , between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.1 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on December 22 , 202 1 , Commission File Number 1-9172.
10.14*						NACCO Industries, Inc. Short-Term Incentive Compensation Plan (Effective as of March 1, 2019) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on February 13, 2019, Commission File Number 1-9172.
10.15*						The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.12 to the Company’s Current Report on Form 8-K, filed by the Company on December 19, 2007, Commission File Number 1-9172.
10.16*						Amendment No. 1 to The North America Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.41 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2009, Commission File Number 1-9172.
10.17*						The North American Coal Corporation Annual Incentive Compensation Plan (Amended and Restated Effective March 1, 2015) is incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K, filed by the Company on May 18, 2015, Commission File Number 1-9172.

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Exhibit Number						Exhibit Description
10.18*						Amendment No. 2 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.40 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2010, Commission File Number 1-9172.
10.19						Coteau Lignite Sales Agreement by and between The Coteau Properties Company and Dakota Coal Company, dated as of January 1, 1990, is incorporated herein by reference to Exhibit 10.11 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.20						First Amendment to Coteau Lignite Sales Agreement by and between The Coteau Properties Company and Dakota Coal Company, dated as of June 1, 1994, is incorporated herein by reference to Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.21						Second Amendment to Coteau Lignite Sales Agreement by and between The Coteau Properties Company and Dakota Coal Company, dated as of January 1, 1997, is incorporated herein by reference to Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.22						Option and Put Agreement by and among The North American Coal Corporation, Dakota Coal Company and the State of North Dakota, dated as of January 1, 1990, is incorporated herein by reference to Exhibit 10.14 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.23						First Amendment to the Option and Put Agreement by and among The North American Coal Corporation, Dakota Coal Company and the State of North Dakota, dated as of June 1, 1994, is incorporated herein by reference to Exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.24						Lignite Sales Agreement by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, dated as of April 1, 1998, is incorporated herein by reference to Exhibit 10.16 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.25						First Amendment to Lignite Sales Agreement by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, dated as of August 30, 2016, is incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q, filed by the Company on November 1, 2016, Commission File Number 1-9172.+
10.26						Pay Scale Agreement by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, dated as of September 29, 2005, is incorporated herein by reference to Exhibit 10.17 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.27						Consent and Agreement by and among Mississippi Lignite Mining Company, Choctaw Generation Limited Partnership, SE Choctaw L.L.C. and Citibank, N.A., dated as of December 20, 2002, is incorporated herein by reference to Exhibit 10.29 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.28						Amendment No. 1 to Lignite Sales Agreement, Settlement Agreement and Release by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, LLLP, dated as of November 16, 2018, is incorporated herein by reference to Exhibit 10.33 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2018, Commission File Number 1-9172.
10.29**						Amendment No. 2 to Lignite Sales Agreement, Settlement Agreement and Release by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, LLLP, dated as of November 24, 2021.
10.30						Second Restatement of Coal Sales Agreement by and between The Falkirk Mining Company and Great River Energy, dated as of January 1, 2007, is incorporated herein by reference to Exhibit 10.18 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.31						Amendment No. 1 to Second Restatement of Coal Sales Agreement, by and between The Falkirk Mining Company and Great River Energy, dated as of January 21, 2011, is incorporated herein by reference to Exhibit 10.19 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.32						Amendment No. 2 to Second Restatement of Coal Sales Agreement, by and between The Falkirk Mining Company and Great River Energy, dated as of March 1, 2014, is incorporated herein by reference to Exhibit 10.52 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2013, Commission File Number 1-9172.
10.33						Amendment No. 3 to Second Restatement of Coal Sales Agreement, by and between The Falkirk Mining Company and Great River Energy, dated as of January 1, 2019, is incorporated herein by reference to Exhibit 10.37 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2018, Commission File Number 1-9172.

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Exhibit Number						Exhibit Description
10.34						Restatement of Option Agreement by and among The Falkirk Mining Company, Cooperative Power Association, United Power Association, and the State of North Dakota, dated as of January 1, 1997, is incorporated herein by reference to Exhibit 10.20 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.35						Termination Agreement and Release, by and among The Falkirk Mining Company, Great River Energy and NoDak Energy Investments Corporation, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.36**						Amendment No. 1 to Termination Agreement and Release, by and between The Falkirk Mining Company, NoDak Energy Investments Corporation and Great River Energy, dated as of December 28, 2021.
10.37 ***						Coal Sales Agreement, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.38 ***						Guaranty by REMC Assets, LP, dated June 17, 2021, is incorporated herein by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.39 ***						Mortgage, Assignment of Leases, Rents and As-Extracted Collateral, Security Agreement, Financing Statement and Fixture Filing, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.40						Security Agreement, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.41						Option Agreement, by and between The Falkirk Mining Company, Rainbow Energy Center, LLC and the State of North Dakota, Doing Business as The Bank of North Dakota, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.
10.42						Third Restatement of Lignite Mining Agreement by and between The Sabine Mining Company and Southwestern Electric Power Company, dated as of January 1, 2008, is incorporated herein by reference to Exhibit 10.21 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+
10.43						Amendment No. 1 to Third Restatement of Lignite Mining Agreement by and between The Sabine Mining Company and Southwestern Electric Power Company, dated as of October 18, 2013 is incorporated herein by reference to Exhibit 10.43 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2014, Commission File Number 1-9172.
10.44						Option Agreement by and among The North American Coal Corporation, Southwestern Electric Power Company and Longview National Bank, dated as of January 15, 1981, is incorporated herein by reference to Exhibit 10.22 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.45						Addendum to Option Agreement, by and among The North American Coal Corporation, Southwestern Electric Power Company and Longview National Bank, dated as of January 15, 1981 is incorporated herein by reference to Exhibit 10.23 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.46						Amendment to Option Agreement, by and among The North American Coal Corporation, Southwestern Electric Power Company and Longview National Bank, dated as of December 2, 1996, is incorporated herein by reference to Exhibit 10.24 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.47						Second Amendment to Option Agreement, by and among The North American Coal Corporation, Southwestern Electric Power Company and Regions Bank, dated as of January 1, 2008, is incorporated herein by reference to Exhibit 10.25 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.48						Agreement by and among The North American Coal Corporation, Southwestern Electric Power Company, Texas Commerce Bank-Longview, Nortex Mining Company and The Sabine Mining Company, dated as of June 30, 1988, is incorporated herein by reference to Exhibit 10.26 to the Company’s Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.
10.49						Lignite Sales Agreement between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co. and Northwestern Corporation dated as of October 10, 2012 is incorporated herein by reference to Exhibit 10.58 to the Company’s Annual Report on Form 10-K, filed by the Company on March 6, 2013, Commission File Number 1-9172.++

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Exhibit Number						Exhibit Description
10.50						First Amendment to Lignite Sales Agreement, dated as of January 30, 2014, between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. and NorthWestern Corporation is incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 8-K, filed by the Company on January 30, 2014, Commission File Number 1-9172.
10.51						Second Amendment to Lignite Sales Agreement, dated as of March 16, 2015, between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., and NorthWestern Corporation is incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q, filed by the Company on May 5, 2015, Commission File Number 1-9172.
10.52*						Amendment No. 3 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on October 30, 2013, Commission File Number 1-9172.
10.53*						Amendment No. 4 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.54 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2014, Commission File Number 1-9172.
10.54*						Amendment No. 5 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.57 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2015, Commission File Number I-9172.
10.55*						Amendment No. 6 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.52 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, Commission File Number I-9172.
10.56						Agreement, dated as of March 16, 2015, among The North American Coal Corporation, Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. and Northwestern Corporation is incorporated herein by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q, filed by the Company on May 5, 2015, Commission File Number 1-9172.
10.57						The North American Coal Corporation Excess Retirement Plan (Amended and Restated Effective January 1, 2020) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on December 18, 2019, Commission File Number 1-9172.
10.58						Amended and Restated Credit Agreement by and among The North American Coal Corporation and the Lenders party thereto and KeyBank National Association as Syndication Agent, PNC Bank National Association as Administrative Agent and KeyBanc Capital Markets Inc. and PNC Capital Markets LLC as Joint Lead Arrangers and Joint Bookrunners, dated as of August 11, 2017 is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on August 15, 2017, Commission File Number 1-9172.
10.59						Amended and Restated Credit Agreement by and among The North American Coal Corporation and the Guarantors party thereto and the Lenders party thereto and KeyBank National Association as Syndication Agent, PNC Bank National Association as Administrative Agent and KeyBanc Capital Markets Inc. and PNC Capital Markets LLC as Joint Lead Arrangers and Joint Bookrunners, dated as of November 12, 2021 is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on November 15, 2021, Commission File Number 1-9172.
10.60						Revolving Credit Commitment Increase Agreement, dated as of December 10, 2021 is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on December 13, 2021. Commission File Number 1-9172.

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(21) Subsidiaries. A list of the subsidiaries of the Company is attached hereto as Exhibit 21.

(23) Consents of experts and counsel.


23.1						Consents of experts and counsel.

(24) Powers of Attorney.


24.1						A copy of a power of attorney for John S. Dalrymple is attached hereto as Exhibit 24.1.
24.2						A copy of a power of attorney for John P. Jumper is attached hereto as Exhibit 24.2.
24.3						A copy of a power of attorney for Dennis W. LaBarre is attached hereto as Exhibit 24.3.
24.4						A copy of a power of attorney for Michael S. Miller is attached hereto as Exhibit 24.4.
24.5						A copy of a power of attorney for Richard de J. Osborne is attached hereto as Exhibit 24.5.
24.6						A copy of a power of attorney for Alfred M. Rankin, Jr. is attached hereto as Exhibit 24.6.
24.7						A copy of a power of attorney for Matthew M. Rankin is attached hereto as Exhibit 24.7.
24.8						A copy of a power of attorney for Roger F. Rankin is attached hereto as Exhibit 24.8.
24.9						A copy of a power of attorney for Lori J. Robinson is attached hereto as Exhibit 24.9.
24.10						A copy of a power of attorney for Robert S. Shapard is attached hereto as Exhibit 24.10.
24.11						A copy of a power of attorney for Britton T. Taplin is attached hereto as Exhibit 24.11.

(31) Rule 13a-14(a)/15d-14(a) Certifications.


31(i)(1)						Certification of J.C. Butler, Jr. pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act is attached hereto as Exhibit 31(i)(1).
31(i)(2)						Certification of Elizabeth I. Loveman pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act is attached hereto as Exhibit 31(i)(2).
(32)						Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed and dated by J.C. Butler, Jr. and Elizabeth I. Loveman.
(95)						Mine Safety Disclosure Exhibit is attached hereto as Exhibit 95.
96.1**						Technical Report Summary relating to The Coteau Properties Company, dated December 31, 2021.
96.2**						Technical Report Summary relating to the Coyote Creek Mining Company, LLC., dated December 31, 2021.
96.3**						Technical Report Summary relating to The Falkirk Mining Company, dated December 31, 2021.
96.4**						Technical Report Summary relating to the Mississippi Lignite Mining Company, dated December 31, 2021.
96.5**						Supplemental Figures Attachment
(99.1**)						Reserve Report of Catapult Mineral Partners.
(99.2**)						Supplemental Figures Attachment

101.INS						Inline XBRL Instance Document
101.SCH						Inline XBRL Taxonomy Extension Schema Document
101.CAL						Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF						Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB						Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE						Inline XBRL Taxonomy Extension Presentation Linkbase Document
104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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*						Management contract or compensation plan or arrangement required to be filed as an exhibit pursuant to Item15(b) of this Annual Report on Form 10-K.

**						Filed herewith.

***						Certain confidential information contained in this agreement has been omitted because it (i) is not material and (ii) would be competitively harmful if publicly disclosed.

+						Portions of Exhibit have been omitted and filed separately with the Securities and Exchange Commission in reliance on Rule 24b-2 and an Order from the Commission granting the Company's request for confidential treatment dated March 27, 2013. Portions for which confidential treatment has been granted have been marked with three asterisks [***] and a footnote indicating "Confidential treatment requested".

++						Portions of Exhibit have been omitted and filed separately with the Securities and Exchange Commission in reliance on Rule 24b-2 and an Order from the Commission granting the Company's request for confidential treatment dated April 2, 2013. Portions for which confidential treatment has been granted have been marked with three asterisks [***] and a footnote indicating "Confidential treatment requested".

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

NACCO Industries, Inc.

By:

/s/ Elizabeth I. Loveman

Elizabeth I. Loveman

Vice President and Controller
(principal financial and accounting officer)

March 2, 2022

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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


/s/ J.C. Butler, Jr.	President and Chief Executive Officer (principal executive officer)	March 2, 2022
J.C. Butler, Jr.

/s/ Elizabeth I. Loveman	Vice President and Controller (principal financial and accounting officer)	March 2, 2022
Elizabeth I. Loveman

*John S. Dalrymple	Director	March 2, 2022
John S. Dalrymple

* John P. Jumper	Director	March 2, 2022
John P. Jumper

* Dennis W. LaBarre	Director	March 2, 2022
Dennis W. LaBarre

* Michael S. Miller	Director	March 2, 2022
Michael S. Miller

* Richard de J. Osborne	Director	March 2, 2022
Richard de J. Osborne

* Alfred M. Rankin, Jr.	Director	March 2, 2022
Alfred M. Rankin, Jr.

* Matthew M. Rankin	Director	March 2, 2022
Matthew M. Rankin

* Roger F. Rankin	Director	March 2, 2022
Roger F. Rankin

*Lori J. Robinson	Director	March 2, 2022
Lori J. Robinson

*Robert S. Shapard	Director	March 2, 2022
Robert S. Shapard

* Britton T. Taplin	Director	March 2, 2022
Britton T. Taplin

* Elizabeth I. Loveman, by signing her name hereto, does hereby sign this Form 10-K on behalf of each of the above named and designated directors of the Company pursuant to a Power of Attorney executed by such persons and filed with the Securities and Exchange Commission.


/s/ Elizabeth I. Loveman						March 2, 2022
Elizabeth I. Loveman, Attorney-in-Fact

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ANNUAL REPORT ON FORM 10-K

ITEM 8, ITEM 15(a)(1) AND (2), AND ITEM 15(c)

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

FINANCIAL STATEMENTS

FINANCIAL STATEMENT SCHEDULES

YEAR ENDED DECEMBER 31, 2021

NACCO INDUSTRIES, INC.

CLEVELAND, OHIO

F-1

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FORM 10-K

ITEM 15(a)(1) AND (2)

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

The following consolidated financial statements of NACCO Industries, Inc. and Subsidiaries and the reports of the Company's independent registered public accounting firm (PCAOB ID:42) are incorporated by reference in Item 8:


Report of Ernst & Young LLP, Independent Registered Public Accounting Firm — For each of the two years in the period ended December 31, 2021 .			F-3
Report of Ernst & Young LLP, Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting — As of December 31, 2021 .			F-5
Consolidated Statements of Operations			F-6
Consolidated Statements of Comprehensive Income (Loss)			F-7
Consolidated Balance Sheets			F-8
Consolidated Statements of Cash Flows			F-9
Consolidated Statements of Equity			F-10
Notes to Consolidated Financial Statements			F-11

The following consolidated financial statement schedules of NACCO Industries, Inc. and Subsidiaries are included in Item 15(c):


Schedule I — Condensed Financial Information of the Parent
Schedule II — Valuation and Qualifying Accounts

All other schedules for which provision is made in the applicable accounting regulation of the SEC are not required under the related instructions or are inapplicable, and therefore have been omitted.

F-2

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of NACCO Industries, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of NACCO Industries, Inc. and Subsidiaries (the Company) as of December 31, 2021 and 2020, the related consolidated statements of operations, comprehensive income (loss), equity and cash flows for the years then ended, and the related notes and the financial statement schedules listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2021 and 2020, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 2, 2022 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit review committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

F-3

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Falkirk and Great River Energy Contract Termination


Description of the Matter			As discussed in Note 1 to the consolidated financial statements, during June 2021, Great River Energy (“GRE”) entered into an agreement to sell Coal Creek Station and the adjacent high-voltage direct current transmission line to Bismarck, North Dakota-based Rainbow Energy Center, LLC (“Rainbow Energy”) and its affiliates. The closing of the transaction between GRE and Rainbow Energy is subject to the satisfaction of certain conditions. Upon completion of the sale of Coal Creek Station, the existing Coal Sales Agreement, the existing Mortgage and Security Agreement and the existing Option Agreement between GRE and the Falkirk Mining Company (“Falkirk”), a wholly owned subsidiary of North American Coal Corporation (“NACoal”), will terminate. If GRE’s efforts to sell the power plant are successful, a new Coal Sales Agreement (“CSA”) between Falkirk and Rainbow Energy will become effective and Falkirk will supply all coal requirements of Coal Creek Station concurrent with Rainbow Energy’s acquisition of the power plant. The Company evaluated whether the GRE announcement in June 2021 was a variable interest entity (“VIE)” reconsideration event and concluded it was not. Auditing the disclosure of the terms of the contract termination was especially complex in determining whether the GRE contract termination and the subsequent agreement between Falkirk and Rainbow Energy will result in a reconsideration event, a change in the conclusion that Falkirk meets the definition of a VIE and the determination of the primary beneficiary of the VIE. Evaluating the Company’s judgments in determining whether an entity is a VIE and the primary beneficiary of the VIE requires a high degree of complex auditor judgment.
How We Addressed the Matter in Our Audit			We obtained an understanding, evaluated and tested the design and operating effectiveness of the controls surrounding the Company’s processes to assess the implications of significant transactions and events that could trigger a VIE reconsideration event. To test the implications of the transaction, our audit procedures included, among other things, inspecting the termination agreement between Falkirk and GRE and new CSA between Falkirk and Rainbow Energy that are both effective upon regulatory approval of the sale of Coal Creek Station and evaluating the VIE assessment performed by the Company. We evaluated the significant terms of the contracts and whether the June 2021 announcement by GRE or the contract termination and subsequent agreement between Falkirk and Rainbow Energy will result in a reconsideration event, a change in the conclusion that Falkirk meets the definition of a VIE and the determination of the primary beneficiary.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2002.

Cleveland, Ohio

March 2, 2022

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Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of NACCO Industries, Inc.

Opinion on Internal Control Over Financial Reporting

We have audited NACCO Industries, Inc. and Subsidiaries’ internal control over financial reporting as of December 31, 20210, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, NACCO Industries, Inc. and Subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2021 consolidated financial statements of the Company and our report dated March 2, 2022 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s report on internal control over financial reporting in Item 9A. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Cleveland, Ohio

March 2, 2022

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NACCO INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended December 31
	2021		2020
	(In thousands, except per share data)
Revenues	$	191,846	$	128,432
Cost of sales	148,394		111,463
Gross profit	43,452		16,969
Earnings of unconsolidated operations	60,843		60,203
Contract termination settlement	10,333		—
Operating expenses
Selling, general and administrative expenses	55,722		53,062
Amortization of intangible assets	3,556		2,572
Gain on sale of assets	(60)		(269)
Asset impairment charges	—		8,359
	59,218		63,724
Operating profit	55,410		13,448
Other (income) expense
Interest expense	1,719		1,354
Interest income	(449)		(1,200)
Closed mine obligations	1,297		1,641
Gain on equity securities	(3,423)		(1,226)
Other, net	(584)		(1,379)
	(1,440)		(810)
Income before income tax provision (benefit)	56,850		14,258
Income tax provision (benefit)	8,725		(535)
Net income	$	48,125	$	14,793

Earnings per share:
Basic earnings per share	$	6.73	$	2.11
Diluted earnings per share	$	6.69	$	2.10

Basic weighted average shares outstanding	7,146		7,026
Diluted weighted average shares outstanding	7,190		7,057

See notes to the Consolidated Financial Statements.

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NACCO INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)


	Year Ended December 31
	2021		2020
	(In thousands)
Net income	$	48,125	$	14,793
Other comprehensive income
Current period pension and postretirement plan adjustment, net of $864 tax expense and $213 tax benefit in 2021 and 2020, respectively	2,851		(697)

Reclassification of pension and postretirement adjustments into earnings, net of $170 and $129 tax benefit in 2021 and 2020, respectively	572		435
Total other comprehensive income	3,423		(262)
Comprehensive income	$	51,548	$	14,531

See notes to the Consolidated Financial Statements.

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NACCO INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31
	2021		2020
	(In thousands, except share data)
ASSETS
Current assets
Cash and cash equivalents	$	86,005	$	88,450
Trade accounts receivable	25,667		18,894
Accounts receivable from affiliates	5,605		4,764
Inventories	54,085		47,551
Refundable federal income taxes	15,054		17,615
Prepaid insurance	2,016		2,564
Other current assets	14,621		8,308
Total current assets	203,053		188,146
Property, plant and equipment, net	193,167		172,417
Intangibles, net	31,774		35,330

Investment in unconsolidated subsidiaries	19,090		28,978

Operating lease right-of-use assets	8,911		10,324
Other non-current assets	51,225		40,984
Total assets	$	507,220	$	476,179
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	12,208	$	5,522
Accounts payable to affiliates	741		125
Revolving credit agreements	—		20,000
Current maturities of long-term debt	2,527		2,112
Asset retirement obligations	1,820		1,844
Accrued payroll	16,339		14,430

Deferred revenue	4,082		941
Other current liabilities	8,299		7,283
Total current liabilities	46,016		52,257
Long-term debt	18,183		24,353
Operating lease liabilities	9,733		11,196
Asset retirement obligations	42,131		39,888
Pension and other postretirement obligations	6,605		8,838
Deferred income taxes	14,792		17,550
Liability for uncertain tax positions	10,113		9,413
Other long-term liabilities	7,531		12,060
Total liabilities	155,104		175,555
Stockholders’ equity
Common stock:
Class A, par value $1 per share, 5,616,568 shares outstanding (2020 - 5,489,615 shares outstanding)	5,616		5,490
Class B, par value $1 per share, convertible into Class A on a one-for-one basis, 1,566,613 shares outstanding (2020 - 1,568,210 shares outstanding)	1,567		1,568
Capital in excess of par value	16,331		10,895
Retained earnings	336,778		294,270
Accumulated other comprehensive loss	(8,176)		(11,599)
Total stockholders’ equity	352,116		300,624
Total liabilities and equity	$	507,220	$	476,179

See notes to the Consolidated Financial Statements.

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NACCO INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31
	2021		2020
	(In thousands)
Operating Activities
Net income	$	48,125	$	14,793

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	23,085		18,114
Amortization of deferred financing fees	326		334
Deferred income taxes	(3,553)		7,517
Stock-based compensation	5,561		3,078
Gain on sale of assets	(60)		(269)
Inventory impairment charge	—		1,973
Other asset impairment charges	—		8,359
Other	1,647		(3,786)
Working capital changes:
Affiliates receivable/payable	495		20
Accounts receivable	(13,685)		42
Inventories	(6,534)		(9,361)
Other current assets	3,320		(2,582)
Accounts payable	7,445		(10,622)
Income taxes receivable/payable	2,699		(10,790)
Other current liabilities	6,004		(19,306)
Net cash provided by (used for) operating activities	74,875		(2,486)

Investing Activities
Expenditures for property, plant and equipment	(39,230)		(30,187)
Acquisition of mineral interests	(5,331)		(14,181)
Proceeds from the sale of assets	633		571
Purchase of equity securities	—		(2,000)
Other	(219)		(187)
Net cash used for investing activities	(44,147)		(45,984)

Financing Activities
Net (reductions) additions to revolving credit agreement	(26,000)		14,000
Additions to long-term debt	3,634		7,427
Reductions to long-term debt	(3,435)		(1,354)
Cash dividends paid	(5,617)		(5,375)
Purchase of treasury shares	—		(1,002)
Other	(1,755)		332
Net cash (used for) provided by financing activities	(33,173)		14,028

Cash and Cash Equivalents
Total decrease for the year	(2,445)		(34,442)
Balance at the beginning of the year	88,450		122,892
Balance at the end of the year	$	86,005	$	88,450

See notes to the Consolidated Financial Statements.

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NACCO INDUSTRIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY


	Class A Common Stock		Class B Common Stock		Capital in Excess of Par Value		Retained Earnings		Accumulated Other Comprehensive (Loss) Income		Total Stockholders' Equity
	(In thousands, except per share data)
Balance, January 1, 2020	$	5,397	$	1,569	$	8,911	$	284,852	$	(11,337)	$	289,392
Stock-based compensation	124		—		2,954		—		—		3,078
Conversion of Class B to Class A shares	1		(1)								—
Purchase of treasury shares	(32)		—		(970)		—		—		(1,002)
Net income	—		—		—		14,793		—		14,793
Cash dividends on Class A and Class B common stock: $0.7675 per share	—		—		—		(5,375)		—		(5,375)
Current period other comprehensive income, net of tax	—		—		—		—		(697)		(697)
Reclassification adjustment to net income, net of tax	—		—		—		—		435		435
Balance, December 31, 2020	$	5,490	$	1,568	$	10,895	$	294,270	$	(11,599)	$	300,624
Stock-based compensation	125		—		5,436		—		—		5,561

Conversion of Class B to Class A shares	1		(1)		—		—		—		—
Net income	—		—		—		48,125		—		48,125
Cash dividends on Class A and Class B common stock: $0.7850 per share	—		—		—		(5,617)		—		(5,617)
Current period other comprehensive income, net of tax	—		—		—		—		2,851		2,851
Reclassification adjustment to net income, net of tax	—		—		—		—		572		572
Balance, December 31, 2021	$	5,616	$	1,567	$	16,331	$	336,778	$	(8,176)	$	352,116

See notes to the Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

NOTE 1—Principles of Consolidation and Nature of Operations

The Consolidated Financial Statements include the accounts of NACCO Industries, Inc.® (“NACCO”) and its wholly owned subsidiaries (collectively, the “Company”). NACCO brings natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through its robust portfolio of NACCO Natural Resources businesses. The Company operates under three business segments: Coal Mining, North American Mining ("NAMining") and Minerals Management. The Coal Mining segment operates surface coal mines for power generation companies and an activated carbon producer. The NAMining segment is a trusted mining partner for producers of aggregates, lithium and other minerals. The Minerals Management segment promotes the development of mineral interests. In addition, Mitigation Resources of North America® ("Mitigation Resources") provides stream and wetland mitigation solutions.

The Company also has items not directly attributable to a reportable segment. Intercompany accounts and transactions are eliminated in consolidation. See Note 15 to the Consolidated Financial Statements for further discussion of segment reporting.

The Company’s operating segments are further described below:

Coal Mining Segment

The Coal Mining segment, operating as The North American Coal Corporation® ("NACoal"), operates surface coal mines under long-term contracts with power generation companies and an activated carbon producer pursuant to a service-based business model. Coal is surface mined in North Dakota, Texas, Mississippi, Louisiana and through September 30, 2021, on the Navajo Nation in New Mexico. Each mine is fully integrated with its customer's operations.

As of December 31, 2021, the Company's operating coal mines were: The Coteau Properties Company (“Coteau”), Coyote Creek Mining Company, LLC (“Coyote Creek”), Demery Resources Company, LLC (“Demery”), The Falkirk Mining Company (“Falkirk”), Mississippi Lignite Mining Company (“MLMC”) and The Sabine Mining Company (“Sabine”).

The contract mining agreement between Bisti Fuels Company, LLC (“Bisti”) and its customer, Navajo Transitional Energy Company ("NTEC") was terminated effective September 30, 2021. As required under the agreement, NTEC paid the Company a termination fee of $10.3 million reported on the line Contract termination settlement on the Consolidated Statements of Operations. As of October 1, 2021, NTEC assumed control and responsibility for operation and all reclamation of the Navajo Mine.

not close. Basin Electric indicated that if it decides to proceed with any changes that could reduce or eliminate the use of coal, the feedstock change is not expected to occur before 2026.

Falkirk operates the Falkirk Mine in North Dakota. Falkirk is the sole supplier of lignite coal to the Coal Creek Station power plant pursuant to a contract under which Falkirk also supplies approximately 0.3 million tons of lignite coal per year to Spiritwood Station power plant. Coal Creek Station and Spiritwood Station are owned by Great River Energy (“GRE”). In May 2020, GRE announced its intent to sell or retire Coal Creek Station and modify Spiritwood Station to be fueled by natural gas.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

closing of this sale is subject to the satisfaction of certain conditions and presently, the transaction is expected to close during the second quarter of 2022.

Falkirk meets the definition of a variable interest entity (“VIE”). The Company concluded that GRE’s May 2020 and June 2021 announcements were not reconsideration events; however, the completion of the Rainbow Energy transaction will result in a reconsideration event. As the terms of the contract between Falkirk and Rainbow Energy are substantially the same as the terms of the contract between Falkirk and GRE, Falkirk is expected to remain a VIE and Rainbow Energy will become the primary beneficiary; therefore, NACCO will continue to account for Falkirk under the equity method.

Upon completion of the sale of Coal Creek Station, the existing Coal Sales Agreement, the existing Mortgage and Security Agreement and the existing Option Agreement between GRE and Falkirk will terminate. Falkirk and GRE have entered into a termination and release of claims agreement. Upon completion of the sale of Coal Creek Station, GRE will pay Falkirk $14.0 million in cash, as well as transfer ownership of an office building located in Bismarck, North Dakota, and convey membership units in Midwest AgEnergy to NACoal. NACCO currently holds a $5.0 million investment in Midwest AgEnergy, which operates two ethanol facilities in North Dakota.

Sabine operates the Sabine Mine in Texas. All production from Sabine is delivered to Southwestern Electric Power Company's (“SWEPCO”) Henry W. Pirkey Plant (the “Pirkey Plant”). SWEPCO is an American Electric Power (“AEP”) company. During 2020, AEP announced its intent to retire the Pirkey Plant in 2023. SWEPCO expects deliveries from Sabine to continue until the first quarter of 2023 at which time Sabine expects to begin final reclamation. Funding for mine reclamation is the responsibility of SWEPCO.

At all operating coal mines other than MLMC, the Company is paid a management fee per ton of coal or heating unit (MMBtu) delivered. Each contract specifies the indices and mechanics by which fees change over time, generally in line with broad measures of U.S. inflation. The customers are responsible for funding all mine operating costs, including final mine reclamation, and directly or indirectly provide all of the capital required to build and operate the mine. This contract structure eliminates exposure to spot coal market price fluctuations while providing income and cash flow with minimal capital investment. Other than at Coyote Creek, debt financing provided by or supported by the customers is without recourse to NACCO and NACoal. See Note 17 for further discussion of Coyote Creek's guarantees.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

All operating coal mines other than MLMC meet the definition of a VIE. In each case, NACCO is not the primary beneficiary of the VIE as it does not exercise financial control; therefore, NACCO does not consolidate the results of these operations within its financial statements. Instead, these contracts are accounted for as equity method investments. The income before income taxes associated with these VIEs is reported as Earnings of unconsolidated operations on the Consolidated Statements of Operations, and the Company’s investment is reported on the line Investments in Unconsolidated Subsidiaries in the Consolidated Balance Sheets. The mines that meet the definition of a VIE are referred to collectively as the “Unconsolidated Subsidiaries.” For tax purposes, the Unconsolidated Subsidiaries are included within the NACCO consolidated U.S. tax return; therefore, the income tax expense line on the Consolidated Statements of Operations includes income taxes related to these entities. See Note 17 for further information on the Unconsolidated Subsidiaries.

NAMining Segment

Minerals Management Segment

The Minerals Management segment derives income primarily by leasing its royalty and mineral interests to third-party exploration and production companies, and, to a lesser extent, other mining companies, granting them the rights to explore, develop, mine, produce, market and sell gas, oil, and coal in exchange for royalty payments based on the lessees' sales of those minerals. During 2021 and 2020, the Minerals Management segment acquired mineral interests, primarily in the Eagle Ford and Permian Basins in Texas and intends to make future acquisitions of mineral and royalty interests that meet the Company’s

acquisition criteria as part of its growth strategy. See Note 20 for further discussion of Mineral Management's acquisitions.

The Company’s legacy royalty and mineral interests are located in Ohio (Utica and Marcellus shale natural gas), Louisiana (Haynesville shale and Cotton Valley formation natural gas), Texas (Cotton Valley and Austin Chalk formation natural gas), Mississippi (coal), Pennsylvania (coal, coalbed methane and Marcellus shale natural gas), Alabama (coal, coalbed methane and natural gas) and North Dakota (coal, oil and natural gas). The majority of the Company’s legacy reserves were acquired as part of its historical coal mining operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

NOTE 2—Significant Accounting Policies

Use of Estimates: The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and judgments. These estimates and judgments affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities (if any) at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents: Cash and cash equivalents include cash in banks and highly liquid investments with original maturities of three months or less.

Inventories: Inventories are stated at the lower of cost and net realizable value. The weighted average method is used for inventory valuation.

Property, Plant and Equipment, Net: Property, plant and equipment are initially recorded at cost. Depreciation, depletion and amortization are provided in amounts sufficient to amortize the cost of the assets, including assets recorded under finance leases, over their estimated useful lives using the straight-line method or the units-of-production method. Buildings and building improvements are depreciated over the life of the mine, which is generally 30 years. Estimated lives for machinery and equipment range from three to 15 years. The units-of-production method is used to amortize certain assets based on estimated recoverable tonnages. Repairs and maintenance costs are expensed when incurred, unless such costs extend the estimated useful life of the asset, in which case such costs are capitalized and depreciated. Asset retirement costs associated with asset retirement obligations are capitalized with the carrying amount of the related long-lived asset and depreciated over the asset's estimated useful life.

Royalty Interests in Oil and Natural Gas Properties: The Company follows the successful efforts method of accounting for its royalty and mineral interests. Under this method, costs to acquire mineral and royalty interests in oil and natural gas properties are capitalized when incurred. Acquisitions of royalty interests of oil and natural gas properties are considered asset acquisitions and are recorded at cost. As an owner of mineral and royalty interests and not working interests, the Company is not required to make capital expenditures and did not make capital expenditures to convert proved undeveloped reserves from undeveloped to developed.

Acquisition costs of proved royalty and mineral interests are amortized using the units of production method over the life of the property, which is estimated using proved reserves. For purposes of amortization, interests in oil and natural gas properties are grouped in a reasonable aggregation of properties with common geological structural features or stratigraphic condition.

The Company reviews and evaluates its royalty interests in oil and natural gas properties for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. Proved oil and gas properties are reviewed for impairment when events and circumstances indicate a potential decline in the fair value of such properties below the carrying value, such as a downward revision of the reserve estimates or lower commodity prices. When such events or changes in circumstances occur, the Company estimates the undiscounted future cash flows expected in connection with the properties and compares such future cash flows to the carrying amounts of the properties to determine if the carrying amounts are recoverable. If the carrying value of the properties is determined to not be recoverable based on the undiscounted cash flows, an impairment charge is recognized by comparing the carrying value to the estimated fair value of the properties.

See Note 20 for further discussion of the Company's royalty and mineral interests.

Long-Lived Assets: The Company periodically evaluates long-lived assets for impairment when changes in circumstances or the occurrence of certain events indicate the carrying amount of an asset or asset group may not be recoverable. Upon identification of indicators of impairment, the Company evaluates the carrying value of the asset by comparing the estimated future undiscounted cash flows generated from the use of the asset or asset group and its eventual disposition with the asset's net carrying value. If the carrying value of an asset is considered impaired, an impairment charge is recorded for the amount that the carrying value of the long-lived asset or asset group exceeds its fair value. Fair value is estimated as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. See Note 9 for further discussion of the Company's nonrecurring fair value measurements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

circumstances have occurred, including assumptions about future power plant dispatch levels, changes in future sales price, operating costs and other factors that impact anticipated revenue and customer demand, requires significant judgment. Actual future operating results could differ significantly from these estimates, which may result in an impairment charge in a future period, which could have a substantial impact on the Company’s results of operations.

Coal Supply Agreement: The coal supply agreement represents a long-term supply agreement with MLMC's customer and was recorded based on the fair value at the date of acquisition. The coal supply agreement is amortized based on units of production over the term of the agreement, which expires in 2032. The Company reviews identified intangible assets for impairment when changes in circumstances or the occurrence of certain events indicate potential impairment.

Self-insurance Liabilities: The Company is generally self-insured for medical claims, certain workers’ compensation claims and certain closed mine liabilities. An estimated provision for claims reported and for claims incurred but not yet reported under the self-insurance programs is recorded and revised periodically based on industry trends, historical experience and management judgment. In addition, industry trends are considered within management's judgment for valuing claims. Changes in assumptions for such matters as legal judgments and settlements, inflation rates, medical costs and actual experience could cause estimates to change in the near term.

Revenue Recognition: See Note 3 to the Consolidated Financial Statements for discussion of revenue recognition.

Stock Compensation: The Company maintains long-term incentive programs that allow for the grant of shares of Class A common stock, subject to restrictions, as a means of retaining and rewarding selected employees for long-term performance and to increase ownership in the Company. Shares awarded under the plans are fully vested and entitle the stockholder to all rights of common stock ownership except that shares may not be assigned, pledged or otherwise transferred during the restriction period. In general, for shares awarded for years ended December 31, 2021 and December 31, 2020, the restriction period ends at the earliest of (i) three years after the participant's retirement date, (ii) three, five or ten years from the award date, or (iii) the participant's death or permanent disability. Pursuant to the plans, the Company issued 138,306 and 79,380 shares related to the years ended December 31, 2021 and 2020, respectively. After the issuance of these shares, there were 561,694 shares of Class A common stock available for issuance under these plans. Compensation expense related to these share awards was $4.1 million ($3.2 million net of tax) and $2.0 million ($1.6 million net of tax) for the years ended December 31, 2021 and 2020, respectively. Compensation expense represents fair value based on the market price of the shares of Class A common stock at the grant date.

The Company also has a stock compensation plan for non-employee directors of the Company under which a portion of the annual retainer for each non-employee director is paid in restricted shares of Class A common stock. For the year ended December 31, 2021, $105,000 ($150,000 for the Chairman) of the non-employee director's annual retainer of $167,000 ($250,000 for the Chairman) was paid in restricted shares of Class A common stock. For the year ended December 31, 2020, $100,000 ($150,000 for the Chairman) of the non-employee director's annual retainer of $162,000 ($250,000 for the Chairman) was paid in restricted shares of Class A common stock. Shares awarded under the plan are fully vested and entitle the stockholder to all rights of common stock ownership except that shares may not be assigned, pledged, hypothecated or otherwise transferred during the restriction period. In general, the restriction period ends at the earliest of (i) ten years from the award date, (ii) the date of the director's death or permanent disability, (iii) five years (or earlier with the approval of the Board of Directors) after the director's date of retirement from the Board of Directors, (iv) the date the director has both retired from the Board of Directors and has reached age 70, or (v) at such other time as determined by the Board of Directors in its sole and absolute discretion. Pursuant to this plan, the Company issued 45,223 and 42,744 shares related to the years ended December 31, 2021 and 2020, respectively. In addition to the mandatory retainer fee received in restricted stock, directors may elect to receive shares of Class A common stock in lieu of cash for up to 100% of the balance of their annual retainer, committee retainer and any committee chairman's fees. These voluntary shares are not subject to any restrictions. Total shares issued under voluntary elections were 753 in 2021 and 745 in 2020. After the issuance of these shares, there were 166,561 shares of Class A common stock available for issuance under this plan. Compensation expense related to these awards was $1.3 million ($1.1 million net of tax) and $1.0 million ($0.8 million net of tax) for the years ended December 31, 2021 and 2020, respectively. Compensation expense represents fair value based on the market price of the shares of Class A common stock at the grant date.

Financial Instruments: Financial instruments held by the Company include cash and cash equivalents, accounts receivable, equity securities, accounts payable, revolving credit agreements and long-term debt.

Fair Value Measurements: The Company accounts for the fair value measurement of its financial assets and liabilities in accordance with U.S. generally accepted accounting principles, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

A fair value hierarchy requires an entity to maximize the use of observable inputs, where available, and minimize the use of unobservable inputs when measuring fair value.

Described below are the three levels of inputs that may be used to measure fair value:

Level 1 - Quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.

Level 2 - Observable prices that are based on inputs not quoted on active markets, but corroborated by market data.

Level 3 - Unobservable inputs are used when little or no market data is available.

The hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The classification of fair value measurements within the hierarchy is based upon the lowest level of input that is significant to the measurement. See Note 9 for further discussion of fair value measurements.

NOTE 3—Revenue Recognition

Nature of Performance Obligations

At contract inception, the Company assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promised good or service that is distinct. To identify the performance obligations, the Company considers all of the goods or services promised in the contract regardless of whether they are explicitly stated or are implied by customary business practices.

Each mine or mine area has a contract with its respective customer that represents a contract under ASC 606. For its consolidated entities, the Company’s performance obligations vary by contract and consist of the following:

At MLMC, each MMBtu delivered during the production period is considered a separate performance obligation. Revenue is recognized at the point in time that control of each MMBtu of lignite transfers to the customer. Fluctuations in revenue from period to period generally result from changes in customer demand.

During 2020, Caddo Creek entered into a fixed-price contract to perform mine reclamation. The management service to perform mine reclamation is the performance obligation accounted for as a series. Performance momentarily creates an asset that the customer simultaneously receives and consumes; therefore, control is transferred to the customer over time. Revenue from this contract is recognized over time utilizing the cost-to-cost method to measure the extent of progress toward completion of the performance obligation. The Company believes the cost-to-cost method is the most appropriate method to measure progress and that the rate at which costs are incurred to fulfill the contract best depicts the transfer of control to the customer. The extent of progress towards completion is measured based on the ratio of costs incurred to date compared to total estimated costs at completion, and revenue is recorded proportionally based on an estimated profit margin.

At NAMining, the management service to oversee the operation of the equipment and delivery of aggregates or other minerals is the performance obligation accounted for as a series. Performance momentarily creates an asset that the customer simultaneously receives and consumes; therefore, control is transferred to the customer over time. Consistent with the conclusion that the customer simultaneously receives and consumes the benefits provided, an input-based measure of progress is appropriate. As each month of service is completed, revenue is recognized for the amount of actual costs incurred, plus the management fee or fixed fee and the general and administrative fee (as applicable). Fluctuations in revenue from period to period result from changes in customer demand primarily due to increases and decreases in activity levels on individual contracts and variances in reimbursable costs.

The Minerals Management segment enters into contracts which grant the right to explore, develop, produce and sell minerals controlled by the Company. These arrangements result in the transfer of mineral rights for a period of time; however, no rights to the actual land are granted other than access for purposes of exploration, development, production and sales. The mineral rights revert back to the Company at the expiration of the contract.

Under these contracts, granting exclusive right, title, and interest in and to minerals, if any, is the performance obligation. The performance obligation under these contracts represents a series of distinct goods or services whereby each day of access that is provided is distinct. The transaction price consists of a variable sales-based royalty and, in certain arrangements, a fixed component in the form of an up-front lease bonus payment. As the amount of consideration the Company will ultimately be entitled to is entirely susceptible to factors outside its control, the entire amount of variable consideration is constrained at contract inception. The Company believes that the pricing provisions of royalty contracts are customary in the industry. Up-

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NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

front lease bonus payments represent the fixed portion of the transaction price and are recognized over the primary term of the contract, which is generally five years.

Significant Judgments

The Company’s contracts with its customers contain different types of variable consideration including, but not limited to, management fees that adjust based on volumes or MMBtu delivered, however, the terms of these variable payments relate specifically to the Company's efforts to satisfy one or more, but not all of, the performance obligations (or to a specific outcome from satisfying the performance obligations) in the contract. Therefore, the Company allocates each variable payment (and subsequent changes to that payment) entirely to the specific performance obligation to which it relates. Management fees, as well as general and administrative fees, are also adjusted based on changes in specified indices (e.g., CPI) to compensate for general inflation changes. Index adjustments, if applicable, are effective prospectively.

Recognition of revenue and recognition of profit related to the Caddo Creek contract requires the use of assumptions and estimates related to the total contract value, the total cost at completion, and the measurement of progress towards completion of the performance obligation. Due to the nature of the contract, developing the estimated total contract value and total cost at completion requires the use of significant judgment. The total contract value includes variable consideration. The Company includes variable consideration in the transaction price at the most likely amount to be earned, based upon the Company’s assessment of expected performance. The Company records these amounts only to the extent it is probable that a significant reversal of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is resolved.

Cost Reimbursement

Certain contracts include reimbursement from customers of actual costs incurred for the purchase of supplies, equipment and services in accordance with contractual terms. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof is highly dependent on factors outside of the Company’s control. Accordingly, reimbursable revenue is fully constrained and not recognized until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. The Company is considered a principal in such transactions and records the associated revenue at the gross amount billed to the customer with the related costs recorded as an expense within cost of sales.

Prior Period Performance Obligations

The Company records royalty income in the month production is delivered to the purchaser. As a non-operator, the Company has limited visibility into when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the purchaser of the product and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded in "Trade accounts receivable" in the accompanying Consolidated Balance Sheets. The difference between the Company’s estimates and the actual amounts received is recorded in the month that payment is received from the third-party lessee. During 2021, the Company recognized $1.8 million of variable consideration that was previously constrained due to uncertainty of collectability. During 2020, royalty income recognized in the reporting period related to performance obligations satisfied in prior reporting periods was immaterial.

Disaggregation of Revenue

In accordance with ASC 606-10-50, the Company disaggregates revenue from contracts with customers into major goods and service lines and timing of transfer of goods and services. The Company determined that disaggregating revenue into these categories achieves the disclosure objective of depicting how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. The Company’s business consists of the Coal Mining, NAMining and Minerals Management segments as well as Unallocated Items. See Note 15 to the Consolidated Financial Statements for further discussion of segment reporting.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

The following table disaggregates revenue by major sources for the years ended December 31:


Major Goods/Service Lines	2021		2020
Coal Mining	$	91,851	$	72,088
NAMining	69,924		42,392
Minerals Management	31,003		14,721
Unallocated Items	4,695		2,133
Eliminations	(5,627)		(2,902)
Total revenues	$	191,846	$	128,432

Timing of Revenue Recognition
Goods transferred at a point in time	$	80,515	$	68,073
Services transferred over time	111,331		60,359
Total revenues	$	191,846	$	128,432

Contract Balances

The opening and closing balances of the Company’s current and long-term contract liabilities and receivables are as follows:


	Contract balances
	Trade accounts receivable		Contract asset (long-term)		Contract liability (current)		Contract liability (long-term)
Balance at January 1, 2021	$	18,894	$	4,984	$	941	$	3,626
Balance at December 31, 2021	25,667		5,985		4,082		488
Increase (decrease)	$	6,773	$	1,001	$	3,141	$	(3,138)

As described above, the Company enters into royalty contracts that grant exclusive right, title, and interest in and to minerals. The transaction price consists of a variable sales-based royalty and, in certain arrangements, a fixed component in the form of an up-front lease bonus payment. The timing of the payment of the fixed portion of the transaction price is upfront, however, the performance obligation is satisfied over the primary term of the contract, which is generally five years. Therefore, at the time any such up-front payment is received, a contract liability is recorded which represents deferred revenue. The difference between the opening and closing balance of this contract liability, which is shown above, primarily results from the difference between new lease bonus payments received and amortization of up-front lease bonus payments received in previous periods.

The amount of revenue recognized in the years ended December 31, 2021 and December 31, 2020 that was included in the opening contract liability was $1.4 million and $0.9 million, respectively. This revenue consists of up-front lease bonus payments received under royalty contracts that are recognized over the primary term of the royalty contracts, which are generally five years. The Company expects to recognize $4.1 million in 2022, $0.3 million in 2023, $0.1 million in 2024, and de minimis amounts in 2025 and 2026 related to the contract liability remaining at December 31, 2021. The difference between the opening and closing balances of the Company’s contract balances results from the timing difference between the Company’s performance and the customer’s payment.

The Company has no contract assets recognized from the costs to obtain or fulfill a contract with a customer.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

NOTE 4—Inventories

Inventories are summarized as follows:


	December 31
	2021		2020
Coal	$	19,352	$	17,695
Mining supplies	34,733		29,856
Total inventories	$	54,085	$	47,551

During 2020, the Company recorded a $2.0 million inventory impairment charge in the line “Cost of sales” in the accompanying Consolidated Statements of Operations as mining costs exceeded net realizable value at MLMC.

NOTE 5—Property, Plant and Equipment, Net

Property, plant and equipment, net includes the following:


	December 31
	2021		2020
Coal lands and real estate	$	52,011	$	50,887
Mineral interests	19,512		14,181
Plant and equipment	264,110		231,190
Property, plant and equipment, at cost	335,633		296,258
Less allowances for depreciation, depletion and amortization	142,466		123,841
	$	193,167	$	172,417

Total depreciation, depletion and amortization expense on property, plant and equipment was $19.5 million and $15.5 million during 2021 and 2020, respectively.

NOTE 6—Intangible Assets

The Company has a coal supply agreement intangible asset which is subject to amortization based on units of production over the term of the lignite sales agreement which expires in 2032. The gross and net balances are set forth in the following table:


	Gross Carrying Amount		Accumulated Amortization		Net Balance
Balance at December 31, 2021
Coal supply agreement	$	84,200	$	(52,426)	$	31,774

Balance at December 31, 2020
Coal supply agreement	$	84,200	$	(48,870)	$	35,330

Amortization expense for intangible assets was $3.6 million and $2.6 million in 2021 and 2020, respectively.

Expected annual amortization expense of the coal supply agreement for the next five years is $3.1 million in 2022 through 2026.

NOTE 7—Asset Retirement Obligations

The Company’s obligations associated with the retirement of long-lived assets are recognized at fair value at the time the legal

obligations are incurred. Upon initial recognition of a liability, a corresponding amount is capitalized as part of the carrying

value of the related long-lived asset and is depreciated either by the straight-line method or the units-of-production method. The

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NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

liability is accreted each period until the liability is settled, at which time the liability is removed. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

The Company's asset retirement obligations are principally for costs to close its surface mines and reclaim the land it has disturbed as a result of its normal mining activities as well as for costs to dismantle certain mining equipment at the end of the life of the mine. Management’s estimate involves a high degree of subjectivity. In particular, the obligation’s fair value is determined using a discounted cash flow technique and is based upon mining permit requirements and various assumptions including credit adjusted risk-free-rates, estimates of disturbed acreage, life of the mine, estimated reclamation costs, the application of various environmental laws and regulation and assumptions regarding equipment productivity. The Company reviews its asset retirement obligations at each mine site at least annually and makes necessary adjustments for permit changes and for revisions of estimates of the timing and extent of reclamation activities and cost estimates.

The accretion of the liability is being recognized over the estimated life of each individual asset retirement obligation and is recorded in the line “Cost of sales” in the accompanying Consolidated Statements of Operations. The associated asset is recorded in “Property, Plant and Equipment, net” in the accompanying Consolidated Balance Sheets. The depreciation of the asset is recorded in the line “Cost of sales” in the accompanying Consolidated Statements of Operations.

A reconciliation of the Company's beginning and ending aggregate carrying amount of the asset retirement obligations are as follows:


	Coal Mining		NAMining		Unallocated Items		NACCO Consolidated
Balance at January 1, 2020	$	19,015	$	604	$	17,240	$	36,859
Liabilities incurred during the period	9,809		—		—		9,809
Liabilities settled during the period	(5,977)		—		(732)		(6,709)
Accretion expense	1,793		—		1,022		2,815
Revision of estimated cash flows	400		(604)		(838)		(1,042)
Balance at December 31, 2020	$	25,040	$	—	$	16,692	$	41,732
Liabilities settled during the period	(184)		—		(869)		(1,053)
Accretion expense	1,996		—		1,304		3,300
Revision of estimated cash flows	46		—		(74)		(28)
Balance at December 31, 2021	$	26,898	$	—	$	17,053	$	43,951

Asset retirement obligations are incurred at the time development of a new mine or mine area commences. During 2020, MLMC began development of a new mine area and as such, recorded an additional $9.8 million asset retirement obligation and a corresponding $9.8 million asset was capitalized as a component of Property, plant and equipment, net. The asset retirement obligation’s fair value was determined using a discounted cash flow technique and is based upon permit requirements and various estimates and assumptions that would be used by market participants, including estimates of disturbed acreage, reclamation costs and assumptions regarding equipment productivity.

Centennial Natural Resources (“Centennial”) ceased coal production at the end of 2015. During 2020, the Company transferred the mine permits for certain Centennial mines to an unrelated third party. As a result of the transfer of the mine permits, the Company was relieved of the associated mine reclamation obligations and therefore recorded a $4.8 million reduction to Centennial's asset retirement obligation, included in "Liabilities settled during the period" in the table above. As part of the transfer of the mine permits, the Company also paid $3.8 million of cash, recorded $1.4 million in Other assets for amounts owed to Centennial from the third-party acquirer, and recognized $2.4 million in Other long-term liabilities in the Consolidated Balance Sheets. The Other long-term liabilities are primarily associated with amounts due to the third-party acquirer upon replacement of outstanding letters of credit.

Bellaire Corporation (“Bellaire”) is a non-operating subsidiary of the Company with legacy liabilities relating to closed mining operations, primarily former Eastern U.S. underground coal mining operations. These legacy liabilities include obligations for water treatment and other environmental remediation that arose as part of the normal course of closing these underground mining operations. The accretion of the liability is recognized over the estimated life of the asset retirement obligation and is recorded in the line “Closed mine obligations” in the accompanying Consolidated Statements of Operations. Since Bellaire's properties are no longer active operations, no associated asset has been capitalized.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

Prior to 2020, Bellaire established a $5.0 million Mine Water Treatment Trust to provide a financial assurance mechanism in order to assure the long-term treatment of post-mining discharges. The fair value of Bellaire's Mine Water Treatment assets, which are recognized as a component of Other non-current assets on the Consolidated Balance Sheets, are $12.3 million and $11.1 million at December 31, 2021 and December 31, 2020, respectively, and are legally restricted for purposes of settling the Bellaire asset retirement obligation. See Note 9 for further discussion of the Mine Water Treatment Trust.

NOTE 8—Current and Long-Term Financing

Financing arrangements are obtained and maintained at the subsidiary level. NACCO has not guaranteed any borrowings of its subsidiaries.

The following table summarizes the Company's available and outstanding borrowings:


	December 31
	2021			2020
Total outstanding borrowings of NACoal:
Revolving credit agreement	$	4,000		$	30,000
Other debt	16,710			16,465
Total debt outstanding	$	20,710		$	46,465

Current portion of borrowings outstanding	$	2,527		$	22,112
Long-term portion of borrowings outstanding	18,183			24,353
	$	20,710		$	46,465

Total available borrowings, net of limitations, under revolving credit agreement	$	120,231		$	146,951

Unused revolving credit agreement	$	116,231		$	116,951

Weighted average stated interest rate on total borrowings	3.7		%	2.3		%

Annual maturities of total debt, excluding leases, are as follows:


2022	2,377
2023	2,460
2024	2,068
2025	5,175
2026	5,492
Thereafter	2,798
	$	20,370

Interest paid on total debt was $1.6 million and $1.4 million during 2021 and 2020, respectively. Deferred financing fees of $1.8 million were capitalized during 2021.

NACoal has a secured revolving line of credit of up to $150.0 million (the “NACoal Facility”) that was refinanced during 2021 and expires in November 2025. Borrowings outstanding under the NACoal Facility were $4.0 million at December 31, 2021. At December 31, 2021, the excess availability under the NACoal Facility was $116.2 million, which reflects a reduction for outstanding letters of credit of $29.8 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

of debt to EBITDA ratios. The commitment fee was 0.35% on the unused commitment at December 31, 2021. The weighted average interest rate applicable to the NACoal Facility at December 31, 2021 was 4.50% including the floating rate margin.

The NACoal Facility contains restrictive covenants, which require, among other things, NACoal to maintain a maximum net debt to EBITDA ratio of 2.75 to 1.00 and an interest coverage ratio of not less than 4.00 to 1.00. The NACoal Facility provides the ability to make loans, dividends and advances to NACCO, with some restrictions based on maintaining a maximum debt to EBITDA ratio of 1.50 to 1.00, or if greater than 1.50 to 1.00, a Fixed Charge Coverage Ratio of 1.10 to 1.00, in conjunction with maintaining unused availability thresholds of borrowing capacity, as defined in the NACoal Facility, of $15.0 million. At December 31, 2021, NACoal was in compliance with all financial covenants in the NACoal Facility.

The obligations under the NACoal Facility are guaranteed by certain of NACoal's direct and indirect, existing and future

domestic subsidiaries, and is secured by certain assets of NACoal and the guarantors, subject to customary exceptions and

limitations.

NACoal has a demand note payable to Coteau, one of the unconsolidated subsidiaries, which bears interest based on the applicable quarterly federal short-term interest rate as announced from time to time by the Internal Revenue Service. At December 31, 2021 and 2020, the balance of the note was $2.6 million and $4.4 million and the interest rate was 0.18% and 0.14%, respectively.

NACoal has six notes payable that are secured by eleven specified units of equipment, bear interest at a weighted average rate of 4.03%, and expire at various dates through 2027. One note includes a principal payment of $4.4 million at the end of the term on December 15, 2026. At December 31, 2021 and 2020, the outstanding balances of the notes were $13.8 million and $10.6 million, respectively.

NOTE 9—Fair Value Disclosure

Recurring Fair Value Measurements: The following table presents the Company's assets accounted for at fair value on a recurring basis:


			Fair Value Measurements at Reporting Date Using
			Quoted Prices in				Significant
			Active Markets for		Significant Other		Unobservable
			Identical Assets		Observable Inputs		Inputs
Description	December 31, 2021		(Level 1)		(Level 2)		(Level 3)
Assets:
Equity securities	$	16,070	$	16,070	$	—	$	—

	$	16,070	$	16,070	$	—	$	—


			Fair Value Measurements at Reporting Date Using
			Quoted Prices in				Significant
			Active Markets for		Significant Other		Unobservable
			Identical Assets		Observable Inputs		Inputs
Description	December 31, 2020		(Level 1)		(Level 2)		(Level 3)
Assets:
Equity securities	$	13,164	$	13,164	$	—	$	—

	$	13,164	$	13,164	$	—	$	—

Bellaire's Mine Water Treatment Trust invests in available for sale securities that are reported at fair value based upon quoted market prices in active markets for identical assets; therefore, they are classified as Level 1 within the fair value hierarchy. The Mine Water Treatment Trust realized a gain of $1.7 million and $1.2 million in the years ended December 31, 2021 and 2020, respectively. See Note 7 for further discussion of Bellaire's Mine Water Treatment Trust.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

During 2020, the Company invested $2.0 million in equity securities of a public company with a diversified portfolio of royalty producing mineral interests. The investment is reported at fair value based upon quoted market prices in active markets for identical assets; therefore, it is classified as Level 1 within the fair value hierarchy. The Company recognized a gain of $1.7 million and $0.1 million in the years ended December 31, 2021 and 2020, related to the investment in these equity securities. The gains related to equity securities are reported on the line Gain on equity securities in the "Other (income) expense" section of the Consolidated Statements of Operations.

There were no transfers into or out of Levels 1, 2 or 3 during the year ended December 31, 2021.

Nonrecurring Fair Value Measurements: The Company regularly performs reviews of potential future development projects and identified certain undeveloped properties where market conditions related to any future development deteriorated during 2020. As a result, the Company estimated the fair value of the assets using unobservable inputs, which are classified as Level 3 inputs. The long-lived assets were written down to their estimated fair value, which resulted in a non-cash asset impairment charge of $7.3 million in the Minerals Management segment and $1.1 million in the Coal Mining segment for certain capitalized leasehold costs, prepaid royalties and other assets during 2020. The fair value of these long-lived assets was determined to be zero as such assets were deemed to have no future economic benefit based on the Company's analysis using market participant assumptions, and therefore no expected future cash flows. The impairment charges are reported on the line Asset impairment charges in the Consolidated Statements of Operations.

Other Fair Value Measurement Disclosures: The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these instruments. The fair values of revolving credit agreements and long-term debt, excluding finance leases, were determined using current rates offered for similar obligations taking into account subsidiary credit risk, which is Level 2 as defined in the fair value hierarchy. The fair value and the book value of revolving credit agreements and long-term debt, excluding finance leases, was $20.5 million and $20.4 million, respectively, at December 31, 2021 and $45.2 million and $45.0 million, respectively, at December 31, 2020.

Financial instruments that potentially subject the Company to concentration of credit risk consist principally of accounts receivable. Under its mining contracts, the Company recognizes revenue and a related receivable as coal or limestone is delivered. These mining contracts provide for monthly settlements. The Company's significant credit concentration is uncollateralized; however, historically minimal credit losses have been incurred. To further reduce credit risk associated with accounts receivable, the Company performs periodic credit evaluations of its customers, but does not generally require advance payments or collateral.

NOTE 10—Leases

The Company recognizes right-of-use assets (“ROU assets”) and lease liabilities for operating leases of real estate, mining and other equipment that expire at various dates through 2031. The majority of the Company's leases are operating leases. See the table below for further information on the Consolidated Balance Sheet. The Company's lease agreements do not contain lease payments that depend on an index or a rate, as such, minimum lease payments do not include variable lease payments.

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NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

Leased assets and liabilities include the following:


Description	Location	DECEMBER 31 2021		DECEMBER 31 2020
Assets
Operating	Operating lease right-of-use assets	$	8,911	$	10,324
Finance	Property, plant and equipment, net (a)	334		1,478


Liabilities
Current
Operating	Other current liabilities	$	1,463	$	1,457
Finance	Current maturities of long-term debt	150		1,188
Noncurrent
Operating	Operating lease liabilities	$	9,733	$	11,196
Finance	Long-term debt	190		280

(a) Finance leased assets are recorded net of accumulated amortization of $0.3 million and $0.2 million as of December 31, 2021 and December 31, 2020, respectively.

The components of lease expense for the years ended December 31 are as follows:


Description	Location	2021		2020
Lease expense
Operating lease cost	Selling, general and administrative expenses	$	2,122	$	2,103
Finance lease cost:
Amortization of leased assets	Cost of sales	220		164
Interest on lease liabilities	Interest expense	31		19
Variable lease expense	Selling, general and administrative expenses	571		588
Short-term lease expense	Selling, general and administrative expenses	1,176		260
Total lease expense		$	4,120	$	3,134

Future minimum finance and operating lease payments were as follows at December 31, 2021:


	Finance Leases		Operating Leases		Total
2022	$	161	$	2,181	$	2,342
2023	127		1,705		1,832
2024	63		1,661		1,724
2025	7		1,469		1,476
2026	—		1,501		1,501
Subsequent to 2026	—		6,451		6,451
Total minimum lease payments	358		14,968		$	15,326
Amounts representing interest	18		3,772
Present value of net minimum lease payments	$	340	$	11,196

F-24

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

As most of the Company's leases do not provide an implicit rate, the Company determines the incremental borrowing rate based on the information available at the lease commencement date in determining the present value of lease payments. The Company considers its credit rating and the current economic environment in determining this collateralized rate. The assumptions used in accounting for ASC 842 for the years ended December 31 are as follows:


Lease term and discount rate	2021		2020
Weighted average remaining lease term (years)
Operating	8.38		8.92
Finance	2.44		1.38

Weighted average discount rate
Operating	7.08	%	7.00	%
Finance	4.16	%	4.11	%

The following table details cash paid for amounts included in the measurement of lease liabilities for the years ended December 31:


Cash paid for amounts included in the measurement of lease liabilities	2021		2020
Operating cash flows from operating leases	$	2,260	$	2,223
Operating cash flows from finance leases	31		19
Financing cash flows from finance leases	275		623

NOTE 11—Contingencies

Various legal and regulatory proceedings and claims have been or may be asserted against NACCO and certain subsidiaries relating to the conduct of their businesses. These proceedings and claims are incidental to the ordinary course of business of the Company. Management believes that it has meritorious defenses and will vigorously defend the Company in these actions. Any costs that management estimates will be paid as a result of these claims are accrued when the liability is considered probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Company does not accrue liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is probable or reasonably possible and which are material, the Company discloses the nature of the contingency and, in some circumstances, an estimate of the possible loss.

These matters are subject to inherent uncertainties, and unfavorable rulings could occur. If an unfavorable ruling were to occur, there exists the possibility of an adverse impact on the Company’s financial position, results of operations and cash flows of the period in which the ruling occurs, or in future periods.

NOTE 12—Stockholders' Equity and Earnings Per Share

NACCO Industries, Inc. Class A common stock is traded on the New York Stock Exchange under the ticker symbol “NC.” Because of transfer restrictions on Class B common stock, no trading market has developed, or is expected to develop, for the Company's Class B common stock. The Class B common stock is convertible into Class A common stock on a one-for-one basis at any time at the request of the holder. The Company's Class A common stock and Class B common stock have the same cash dividend rights per share. As the liquidation and dividend rights are identical, any distribution of earnings would be allocated to Class A and Class B stockholders on a proportionate basis, and accordingly the net income per share for each class of common stock is identical. The Class A common stock has one vote per share and the Class B common stock has ten votes per share. The total number of authorized shares of Class A common stock and Class B common stock at December 31, 2021 was 25,000,000 shares and 6,756,176 shares, respectively. Treasury shares of Class A common stock totaling 2,600,661 and 2,726,017 at December 31, 2021 and 2020, respectively, have been deducted from shares outstanding.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

Stock Repurchase Programs: On November 10, 2021, the Company's Board of Directors approved a stock purchase program ("2021 Stock Repurchase Program") providing for the purchase of up to $20.0 million of the Company’s outstanding Class A common stock through December 31, 2023. NACCO’s previous repurchase program ("2019 Stock Repurchase Program") would have expired on December 31, 2021 but was terminated and replaced by the 2021 Stock Repurchase Program. The Company repurchased 32,286 shares of Class A common stock under the 2019 Stock Repurchase Program for an aggregate purchase price of $1.0 million during 2020.

The timing and amount of any repurchases under the 2021 Stock Repurchase Program are determined at the discretion of the Company's management based on a number of factors, including the availability of capital, other capital allocation alternatives, market conditions for the Company's Class A common stock and other legal and contractual restrictions. The 2021 Stock Repurchase Program does not require the Company to acquire any specific number of shares and may be modified, suspended, extended or terminated by the Company without prior notice and may be executed through open market purchases, privately negotiated transactions or otherwise. All or part of the repurchases under the 2021 Stock Repurchase Program may be implemented under a Rule 10b5-1 trading plan, which would allow repurchases under pre-set terms at times when the Company might otherwise be restricted from doing so under applicable securities laws.

Stock Compensation: See Note 2 for a discussion of the Company's restricted stock awards.

Earnings per Share: The weighted average number of shares of Class A common stock and Class B common stock outstanding used to calculate basic and diluted earnings per share were as follows:


	2021		2020
Basic weighted average shares outstanding	7,146		7,026
Dilutive effect of restricted stock awards	44		31
Diluted weighted average shares outstanding	7,190		7,057

Basic earnings per share	$	6.73	$	2.11
Diluted earnings per share	$	6.69	$	2.10

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

NOTE 13—Income Taxes

The Company provides for income taxes and the related accounts under the asset and liability method. Deferred tax assets and liabilities are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates expected to be in effect during the year in which the basis differences reverse. Valuation allowances are established when management determines it is more likely than not that some portion, or all, of the deferred tax assets will not be realized.

The components of income (loss) before income tax provision (benefit) and the income tax provision (benefit) for the years ended December 31 are as follows:


	2021		2020
Income (loss) before income tax provision (benefit)
Domestic	$	57,019	$	13,990
Foreign	(169)		268
	$	56,850	$	14,258
Income tax provision (benefit)
Current income tax provision (benefit):
Federal	$	10,870	$	(7,859)
State	1,443		(408)
Foreign	(35)		215
Total current	12,278		(8,052)
Deferred income tax (benefit) provision:
Federal	(4,449)		7,847
State	896		(330)

Total deferred	(3,553)		7,517
	$	8,725	$	(535)

The Company made income tax payments of $11.5 million and $0.4 million during 2021 and 2020, respectively. During the same periods, income tax refunds totaled $2.6 million and $4.2 million, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

The provision for income taxes differs from the amount computed by applying the statutory federal income tax rate to income before the provision for income taxes. A reconciliation of the federal statutory and effective income tax rate for the years ended December 31 is as follows:


	2021			2020
Income before income tax provision	$	56,850		$	14,258
Statutory taxes at 21.0%	$	11,939		$	2,994
State and local income taxes	1,890			(626)
Non-deductible expenses	725			426
Percentage depletion	(6,245)			(3,744)
R&D and other federal credits	(363)			(367)
Settlements and uncertain tax positions	166			6,286
Coronavirus Aid, Relief, and Economic Security ("CARES") Act - carryback rate differential	—			(4,741)
Other, net	613			(763)
Income tax provision	$	8,725		$	(535)
Effective income tax rate	15.3		%	(3.8)		%

The Company recorded an income tax expense of $8.7 million for the year ended December 31, 2021 on income before income tax of $56.9 million, or 15.3%, compared to income tax benefit of $0.5 million on income before income tax of $14.3 million, or (3.8%), for the year ended December 31, 2020. The year ended December 31, 2020 includes $7.3 million of discrete tax charges primarily related to settlement of tax examinations, reserves for uncertain tax positions and return to provision adjustments partially offset by a benefit of $4.7 million, primarily due to the rate differential related to carrying back losses under the provisions of the Coronavirus Aid, Relief, and Economic Security Act ("CARES Act"). The CARES Act allows net operating tax losses incurred in 2018, 2019, and 2020 to be carried back to each of the five preceding taxable years to generate a refund of previously paid income taxes. The Company generated a net tax operating loss in 2020 primarily due to the realization of certain deferred tax assets. There were no material discrete items affecting income tax expense in 2021.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

A detailed summary of the total deferred tax assets and liabilities in the Company's Consolidated Balance Sheets resulting from differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes is as follows:


	December 31
	2021		2020
Deferred tax assets
Lease liabilities	$	24,500	$	27,800
Tax carryforwards	13,837		17,756
Inventories	4,522		3,742
Accrued liabilities	9,243		10,160
Employee benefits	3,496		2,747
Land valuation adjustment	5,988		5,536
Other	6,527		5,401
Total deferred tax assets	68,113		73,142
Less: Valuation allowance	11,695		11,549
	56,418		61,593
Deferred tax liabilities
Lease right-of-use assets	24,500		27,800
Depreciation and depletion	25,851		31,972
Partnership investment - development costs	9,840		11,686
Accrued pension benefits	10,941		7,685
Total deferred tax liabilities	71,132		79,143
Net deferred liability	$	(14,714)	$	(17,550)

The following table summarizes the tax carryforwards and associated carryforward periods and related valuation allowances where the Company has determined that realization is uncertain:


	December 31, 2021
	Net deferred tax asset		Valuation allowance		Carryforwards expire during:
State net operating loss	$	17,516	$	14,694	2022-2041


	December 31, 2020
	Net deferred tax asset		Valuation allowance		Carryforwards expire during:
State net operating loss	$	18,708	$	14,478	2021-2040
Federal research credit	2,648		—		2034-2040
Total	$	21,356	$	14,478

The Company has a valuation allowance for certain state and foreign deferred tax assets. Based upon the review of historical earnings and the relevant expiration of carryforwards, including utilization limitations in the various state taxing jurisdictions, the Company believes the valuation allowances are appropriate and does not expect to release valuation allowances within the next twelve months that would have a significant effect on the Company's financial position or results of operations.

The tax returns of the Company and certain of its subsidiaries are under routine examination by various taxing authorities. The Company has not been informed of any material assessment for which an accrual has not been previously provided and the Company would vigorously contest any material assessment. Management believes any potential adjustment would not materially affect the Company's financial condition or results of operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

In general, the Company operates in taxing jurisdictions that provide a statute of limitations period ranging from three to five years for the taxing authorities to review the applicable tax filings. The examination of the 2013-2016 U.S. federal tax returns is ongoing. The Company has extended the statute of limitations to allow the U.S. taxing authorities to complete their examination.

The following is a reconciliation of the Company's total gross unrecognized tax benefits, defined as the aggregate tax effect of differences between tax return positions and the benefits recognized in the financial statements for the years ended December 31, 2021 and 2020. The increase in the gross unrecognized tax benefits in 2020 was primarily due to tax positions related to worthlessness losses for which the timing of deductibility is uncertain. Approximately $6.4 million and $6.3 million of the gross unrecognized tax benefits as of December 31, 2021 and 2020, respectively, relate to permanent items that, if recognized, would impact the effective income tax rate. This amount differs from the gross unrecognized tax benefits presented in the table below due to (1) the deferred tax asset which would be available if the position were not sustained upon audit and (2) the decrease in U.S. federal income taxes which would occur upon the recognition of the state tax benefits included herein.


	2021		2020
Balance at January 1	$	10,459	$	2,860
Additions based on tax positions related to prior years	95		2,774
Decreases based on settlements with tax authorities	—		(803)
Additions based on tax positions related to the current year	—		5,628
Balance at December 31	$	10,554	$	10,459

The Company records interest and penalties on uncertain tax positions as a component of the income tax provision. The Company recognized net expense of less than $0.1 million and net benefit of less than $0.1 million in interest and penalties related to uncertain tax positions during 2021 and 2020, respectively. The total amount of interest and penalties accrued was $0.2 million and $0.1 million as of December 31, 2021 and 2020, respectively.

The Company expects the amount of unrecognized tax benefits will change within the next 12 months; however, the change in unrecognized tax benefits, which is reasonably possible within the next 12 months, is not expected to have a significant effect on the Company's financial position, results of operations or cash flows.

NOTE 14—Retirement Benefit Plans

Defined Benefit Plans: The Company maintains defined benefit pension plans that provide benefits based on years of service and average compensation during certain periods. Prior to 2020, the Company amended the Combined Defined Benefit Plan for NACCO Industries, Inc. and its subsidiaries (the “Combined Plan”) to freeze pension benefits for all employees. The Company also amended the Supplemental Retirement Benefit Plan (the “SERP”) to freeze all pension benefits. All eligible employees of the Company, including employees whose pension benefits are frozen, receive retirement benefits under defined contribution retirement plans.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

The assumptions used in accounting for the defined benefit plans were as follows for the years ended December 31:


	2021		2020
Weighted average discount rates for pension benefit obligation	2.53% - 2.77%		2.02% - 2.36%
Weighted average discount rates for net periodic benefit cost	2.02% - 2.36%		2.98% - 3.20%

Expected long-term rate of return on assets for net periodic benefit cost	7.00	%	7.00	%

Set forth below is detail of the net periodic pension income for the defined benefit plans for the years ended December 31:


	2021		2020
Interest cost	$	1,002	$	1,285
Expected return on plan assets	(2,568)		(2,435)
Amortization of actuarial loss	718		597
Amortization of prior service cost	59		58


Net periodic pension income	$	(789)	$	(495)

Set forth below is detail of other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss for the years ended December 31:


	2021		2020
Current year actuarial (gain) loss	$	(3,793)	$	667
Amortization of actuarial loss	(718)		(597)
Amortization of prior service cost	(59)		(58)
Total recognized in other comprehensive (income) loss	$	(4,570)	$	12

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

The following table sets forth the changes in the benefit obligation and the plan assets during the year and the funded status of the defined benefit plans at December 31:


	2021		2020
Change in benefit obligation
Projected benefit obligation at beginning of year	$	44,600	$	41,854
Interest cost	1,002		1,285
Actuarial (gain) loss	(1,367)		3,996
Benefits paid	(2,572)		(2,535)




Projected benefit obligation at end of year	$	41,663	$	44,600
Accumulated benefit obligation at end of year	$	41,663	$	44,600
Change in plan assets
Fair value of plan assets at beginning of year	$	41,099	$	37,364
Actual return on plan assets	4,995		5,763
Employer contributions	487		507
Benefits paid	(2,572)		(2,535)



Fair value of plan assets at end of year	$	44,009	$	41,099
Funded status at end of year	$	2,346	$	(3,501)
Amounts recognized in the balance sheets consist of:
Non-current assets	$	7,806	$	4,070
Current liabilities	(542)		(549)
Non-current liabilities	(4,918)		(7,022)
	$	2,346	$	(3,501)
Components of accumulated other comprehensive loss consist of:
Actuarial loss	$	9,510	$	14,022
Prior service cost	703		761
Deferred taxes	(2,254)		(3,316)

	$	7,959	$	11,467

The Company recognizes as a component of benefit (income) cost, as of the measurement date, any unrecognized actuarial net gains or losses that exceed 10% of the larger of the projected benefit obligations or the plan assets, defined as the "corridor." Amounts outside the corridor are amortized over the average expected remaining service of active participants expected to benefit under the retiree medical plans or over the average expected remaining lifetime of inactive participants for the pension plans. The (gain) loss amounts recognized in AOCI are not expected to be fully recognized until the plan is terminated or as settlements occur, which would trigger accelerated recognition. Prior service costs resulting from plan changes are also in AOCI.

The Company's policy is to make contributions to fund its pension plans within the range allowed by applicable regulations.

The Company maintains one supplemental defined benefit plan that pays monthly benefits to participants directly out of corporate funds. All other pension benefit payments are made from assets of the pension plans.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

Future pension benefit payments expected to be paid from assets of the pension plans are:


2022	$	2,710
2023	2,697
2024	2,716
2025	2,684
2026	2,672
2027 - 2031	12,779
	$	26,258

The expected long-term rate of return on defined benefit plan assets reflects management's expectations of long-term rates of return on funds invested to provide for benefits included in the projected benefit obligations. In establishing the expected long-term rate of return assumption for plan assets, the Company considers the historical rates of return over a period of time that is consistent with the long-term nature of the underlying obligations of these plans as well as a forward-looking rate of return. The historical and forward-looking rates of return for each of the asset classes used to determine the Company's estimated rate of return assumption were based upon the rates of return earned or expected to be earned by investments in the equivalent benchmark market indices for each of the asset classes.

Expected returns for pension plans are based on a calculated market-related value for pension plan assets. Under this methodology, asset gains and losses resulting from actual returns that differ from the Company's expected returns are recognized in the market-related value of assets ratably over three years.

The pension plans maintain investment policies that, among other things, establish a portfolio asset allocation methodology with percentage allocation bands for individual asset classes. The investment policies provide that investments are reallocated between asset classes as balances exceed or fall below the appropriate allocation bands.

The following is the actual allocation percentage and target allocation percentage for the pension plan assets at December 31:


	2021 Actual Allocation		2020 Actual Allocation		Target Allocation Range
U.S. equity securities	48.7	%	45.4	%	36.0% - 54.0%
Non-U.S. equity securities	19.7	%	20.3	%	16.0% - 24.0%
Fixed income securities	31.2	%	33.9	%	30.0% - 40.0%
Money market	0.4	%	0.4	%	0.0% - 10.0%

The defined benefit pension plans do not have any direct ownership of NACCO common stock.

The fair value of each major category of the Company's pension plan assets are valued using quoted market prices in active markets for identical assets, or Level 1 in the fair value hierarchy. Following are the values as of December 31:


	Level 1
	2021		2020
U.S. equity securities	$	21,434	$	18,640
Non-U.S. equity securities	8,678		8,335
Fixed income securities	13,723		13,948

Money market	174		176
Total	$	44,009	$	41,099

Postretirement Health Care: The Company also maintains health care plans which provide benefits to grandfathered eligible retired employees. All health care plans of the Company have a cap on the Company's share of the costs. The health care plans have network provided benefits which result in cost savings for the Company. These plans have no assets. Under the Company's current policy, plan benefits are funded at the time they are due to participants.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

The assumptions used in accounting for the postretirement health care plans are set forth below for the years ended December 31:


	2021		2020
Weighted average discount rates for benefit obligation	2.12	%	1.37	%
Weighted average discount rates for net periodic benefit cost	1.37	%	1.37% - 2.65%
Health care cost trend rate assumed for next year	6.50	%	6.25	%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)	4.50	%	5.00	%
Year that the rate reaches the ultimate trend rate	2029		2027

Set forth below is detail of the net periodic benefit expense (income) for the postretirement health care plans for the years ended December 31:


	2021		2020
Service cost	$	13	$	21
Interest cost	27		52
Amortization of actuarial loss (gain)	19		(1)
Amortization of prior service credit	(54)		(59)
Amortization of curtailment	—		(31)
Net periodic benefit expense (income)	$	5	$	(18)

Set forth below is detail of other changes in plan assets and benefit obligations recognized in other comprehensive loss for the years ended December 31:


	2021		2020
Current year actuarial (gain) loss	$	(48)	$	194
Amortization of actuarial (loss) gain	(19)		1

Amortization of prior service credit	54		59
Amortization of curtailment	—		31
Transfers	126		46
Total recognized in other comprehensive loss	$	113	$	331

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

The following sets forth the changes in benefit obligations during the year and the funded status of the postretirement health care at December 31:


	2021		2020
Change in benefit obligation
Benefit obligation at beginning of year	$	2,054	$	2,049
Service cost	13		21
Interest cost	27		52
Plan amendments	—		49
Actuarial (gain) loss	(48)		145
Benefits paid	(169)		(262)
Benefit obligation at end of year	$	1,877	$	2,054
Funded status at end of year	$	(1,877)	$	(2,054)
Amounts recognized in the balance sheets consist of:
Current liabilities	$	(190)	$	(238)
Noncurrent liabilities	(1,687)		(1,816)
	$	(1,877)	$	(2,054)
Components of accumulated other comprehensive loss consist of:
Actuarial loss	$	520	$	466
Prior service credit	(108)		(167)
Deferred taxes	(195)		(167)
	$	217	$	132

Future postretirement health care benefit payments expected to be paid are:


2022	191
2023	191
2024	182
2025	176
2026	169
2027 - 2031	700
	$	1,609

Defined Contribution Plans: NACCO and its subsidiaries maintain a defined contribution (401(k)) plan for substantially all employees and provide employer matching contributions based on plan provisions. The plan also provides for a minimum employer contribution. Total costs, including Company contributions, for these plans were $2.9 million and $2.8 million in 2021 and 2020, respectively.

NOTE 15—Business Segments

The Company’s operating segments are: (i) Coal Mining, (ii) NAMining and (iii) Minerals Management. The Company determines its reportable segments by first identifying its operating segments, and then by assessing whether any components of these segments constitute a business for which discrete financial information is available and where segment management regularly reviews the operating results of that component. The Company’s Chief Operating Decision Maker utilizes operating profit to evaluate segment performance and allocate resources.

The Company has items not directly attributable to a reportable segment which are not included as part of the measurement of segment operating profit, which are primarily administrative costs related to public company reporting requirements at the parent company and the financial results of Mitigation Resources and Bellaire. Mitigation Resources generates and sells stream

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

and wetland mitigation credits (known as mitigation banking) and provides services to those engaged in permittee-responsible stream and wetland mitigation. Bellaire manages the Company’s long-term liabilities related to former Eastern U.S. underground mining activities.

All financial statement line items below operating profit (other income including interest expense and interest income, the provision for income taxes and net income) are presented and discussed within this Form 10-K on a consolidated basis.

See Note 1 for additional discussion of the Company's reportable segments. All current operations reside in the U.S. The accounting policies of the reportable segments are described in Note 2 and Note 20.

In 2021 and 2020, two customers individually accounted for more than 10% of consolidated revenue. The following represents the revenue attributable to each of these entities as a percentage of consolidated revenue for those years:


	Percentage of Consolidated Revenue
Segment	2021		2020
Coal Mining customer	43	%	55	%
NAMining customer	19	%	19	%

In addition, for the year ended December 31, 2021, the Coal Mining segment derived approximately 68% of the Earnings of Unconsolidated Operations from two customers, Basin Electric and GRE.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

The following tables present revenue, operating profit, depreciation expense and capital expenditures for the years ended December 31:


	2021		2020
Revenues
Coal Mining	$	91,851	$	72,088
NAMining	69,924		42,392
Minerals Management	31,003		14,721
Unallocated Items	4,695		2,133
Eliminations	(5,627)		(2,902)
Total	$	191,846	$	128,432

Operating profit (loss)
Coal Mining	$	49,059	$	25,436
NAMining	109		1,872
Minerals Management	26,080		3,493
Unallocated Items	(19,553)		(17,256)
Eliminations	(285)		(97)
Total	$	55,410	$	13,448



Expenditures for property, plant and equipment and acquisition of mineral interests
Coal Mining	$	16,830	$	14,825
NAMining	21,100		13,862
Minerals Management	6,423		15,474
Unallocated Items	208		207
Total	$	44,561	$	44,368

Depreciation, depletion and amortization
Coal Mining	$	16,649	$	14,213
NAMining	4,435		2,470
Minerals Management	1,858		1,308
Unallocated Items	143		123
Total	$	23,085	$	18,114

Asset information by segment is not discretely maintained for internal reporting or used in evaluating performance.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

NOTE 16—Parent Company Condensed Balance Sheets

The condensed balance sheets of NACCO, the parent company, at December 31 are as follows:


	2021		2020
ASSETS
Cash and cash equivalents	$	83,093	$	85,365
Accounts receivable from affiliates	—		495

Other current assets	17,578		20,648
Investment in subsidiaries	268,720		211,468


Property, plant and equipment, net	57		110
Other non-current assets	4,885		5,890
Total Assets	$	374,333	$	323,976
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	3,865	$	3,242
Current intercompany accounts payable, net	637		2,337

Note payable to Bellaire	16,750		16,750
Other non-current liabilities	965		1,023
Stockholders’ equity	352,116		300,624
Total Liabilities and Stockholders’ Equity	$	374,333	$	323,976

The credit agreement at NACoal allows for the transfer of assets to NACCO under certain circumstances. The amount of NACCO's investment that was restricted at December 31, 2021 totaled approximately $1.8 million. The amount of unrestricted cash available to NACCO included in “Investment in subsidiaries” was $1.2 million at December 31, 2021. Dividends and management fees from its subsidiaries are the primary sources of cash for NACCO.

NOTE 17—Unconsolidated Subsidiaries

Each of the Company's wholly owned Unconsolidated Subsidiaries, within the Coal Mining and NAMining segments, meet the definition of a VIE. The Unconsolidated Subsidiaries are capitalized primarily with debt financing provided by or supported by their respective customers, and generally without recourse to NACCO and NACoal. Although NACoal owns 100% of the equity and manages the daily operations of the Unconsolidated Subsidiaries, the Company has determined that the equity capital provided by NACoal is not sufficient to adequately finance the ongoing activities or absorb any expected losses without additional support from the customers. The customers have a controlling financial interest and have the power to direct the activities that most significantly affect the economic performance of the entities. As a result, the Company is not the primary beneficiary and therefore does not consolidate these entities' financial positions or results of operations. See Note 1 for a discussion of these entities.

The investment in the unconsolidated subsidiaries and related tax positions totaled $19.1 million and $29.0 million at December 31, 2021 and 2020, respectively. The Company's risk of loss relating to these entities is limited to its invested capital, which was $7.6 million and $6.5 million at December 31, 2021 and 2020, respectively.

NACoal is a party to certain guarantees related to Coyote Creek. Under certain circumstances of default or termination of Coyote Creek’s Lignite Sales Agreement (“LSA”), NACoal would be obligated for payment of a "make-whole" amount to Coyote Creek’s third-party lenders. The “make-whole” amount is based on the excess, if any, of the discounted value of the remaining scheduled debt payments over the principal amount. In addition, in the event Coyote Creek’s LSA is terminated on or after January 1, 2024 by Coyote Creek’s customers, NACoal is obligated to purchase Coyote Creek’s dragline and rolling stock for the then net book value of those assets. To date, no payments have been required from NACoal since the inception of these guarantees. The Company believes that the likelihood NACoal would be required to perform under the guarantees is remote, and no amounts related to these guarantees have been recorded.

F-38

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

Summarized financial information for the unconsolidated subsidiaries is as follows:


	2021		2020
Statement of Operations
Revenue	$	764,759	$	768,660
Gross profit	$	68,076	$	69,021
Income before income taxes	$	60,865	$	60,398
Net income	$	53,248	$	50,933
Balance Sheet
Current assets	$	168,669	$	186,934
Non-current assets	$	900,924	$	959,032
Current liabilities	$	98,887	$	143,843
Non-current liabilities	$	963,128	$	995,658

Revenue includes all mine operating costs that are reimbursed by the customers of the Unconsolidated Subsidiaries as well as the compensation per ton of coal, heating unit (MMBtu) or ton of limestone delivered. Reimbursed costs have offsetting expenses and have no impact on income before income taxes. Income before income taxes represents the Earnings of the unconsolidated operations and the Income from other unconsolidated affiliates.

NACoal received dividends of $51.7 million and $49.7 million from the Unconsolidated Subsidiaries in 2021 and 2020, respectively.

NOTE 18—Related Party Transactions

One of the Company's directors is a retired Jones Day partner. Legal services rendered by Jones Day approximated $1.2 million and $1.0 million for the years ended December 31, 2021 and 2020.

Alfred M. Rankin, Jr. continues to serve as the Chairman of the Board of Directors of NACCO and Mr. Rankin supports the President and Chief Executive Officer of NACCO upon request under the terms of a consulting agreement. Fees for consulting services rendered by Mr. Rankin approximated $0.5 million for both of the years ended December 31, 2021 and 2020.

Hyster-Yale Materials Handling, Inc. ("Hyster-Yale") is a former subsidiary of the Company that was spun-off to stockholders in 2012. Mr. Rankin is Chairman, President and Chief Executive Officer of Hyster-Yale Materials Handling and Chairman, Hyster-Yale Group. In the ordinary course of business, NACoal leases or buys Hyster-Yale lift trucks. The terms may not be comparable to terms that would be obtained in a transaction between unaffiliated parties.

NOTE 19—Other Events and Transactions

Voluntary Separation Program: During the fourth quarter of 2020, the Company adopted a voluntary separation program ("2020 VSP") for eligible employees who met certain age and service requirements in an effort to reduce overall headcount at the Company’s headquarters. The irrevocable acceptance period for associates electing to participate in the 2020 VSP ended during December 2020. In the fourth quarter of 2020, the Company recorded pre-tax charges for the 2020 VSP of $1.8 million included in Selling, general and administrative expense in the accompanying Consolidated Statements of Operations.

NOTE 20—Supplemental Oil and Gas Disclosures (Unaudited)

The Minerals Management segment derives income primarily by leasing its royalty and mineral interests to third-party exploration and production companies, and, to a lesser extent, other mining companies, granting them the rights to explore, develop, mine, produce, market and sell gas, oil, and coal in exchange for royalty payments based on the lessees' sales of those minerals. As an owner of royalty and mineral interests, the Company’s access to information concerning activity and operations of its royalty and mineral interests is limited. The Company does not have information that would be available to a company with working interests in oil and natural gas operations because detailed information is not generally available to owners of royalty and mineral interests. See Note 1, Note 2 and Note 15 for additional discussion of the Minerals Management segment.

F-39

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

During 2021 and 2020, the Minerals Management segment acquired additional mineral interests, primarily in the Eagle Ford and Permian Basins in Texas. Total consideration for the 2021 and 2020 acquisitions of mineral and royalty interests was $5.3 million and $14.2 million, respectively. The 2021 acquisitions include 20.6 thousand gross acres and 1.8 thousand net royalty acres. The 2020 acquisitions include 65.5 thousand gross acres and 1.2 thousand net royalty acres. Total oil and gas mineral and royalty interests include approximately 127.8 thousand gross acres and 59.9 thousand net royalty acres at December 31, 2021.

Aggregate capitalized costs related to oil and gas royalty and mineral interests with applicable accumulated depreciation, depletion and amortization at December 31 are as follows:


	2021
Proved developed	$	3,266
Proved undeveloped	16,246
Less: accumulated depreciation, depletion and amortization	868
Net royalty interests in oil and natural gas properties	$	18,644

Total net proved reserves are defined as those natural gas and hydrocarbon liquid reserves to Company interests after deducting all royalties, overriding royalties, and reversionary interests owned by outside parties that become effective upon payout of specified monetary balances. Decline curve analysis was used to estimate the remaining reserves of pressure depletion reservoirs with enough historical production data to establish decline trends. Reservoirs under non-pressure depletion drive mechanisms and non-producing reserves were estimated by volumetric analysis, research of analogous reservoirs, or a combination of both. Reserves have been estimated using deterministic and probabilistic methods. All reserves estimates have been prepared using standard engineering practices generally accepted by the petroleum industry and conform to guidelines developed and adopted by the SEC.


	Net reserves as of December 31, 2021
	Oil (bbl) (1)	NGL (bbl) (1)	Residue gas (Mcf) (2)
Proved developed	167,430	282,230	16,617,360
Proved undeveloped	220	90	1,210
Total	167,650	282,320	16,618,570

(1) Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

(2) Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweighted average of first-day-of-the-month commodity prices for the periods presented. Future cash inflows are computed by applying applicable prices relating to proved reserves to the year-end quantities of those reserves. Future production and costs are derived based on current costs assuming continuation of existing economic conditions. Federal income tax expenses are deducted from future production revenues in the calculation of the standardized measure using the statutory tax rate. The Company is subject to certain state based taxes; however, these amounts are not material. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

F-40

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

(Tabular Amounts in Thousands, Except Per Share and Percentage Data)

The following table provides the future net cash flows relating to proved oil and gas reserves based on the standardized measure of discounted cash flows as of December 31, 2021:


	Gross Amounts		Statutory tax rate		Net Amounts
Future cash inflows	$	71,400
Future production costs	14,664
Future net cash flows before income tax expense	56,736		21	%	44,821
10% discount to reflect timing of cash flows	(19,897)		21	%	(15,719)
Standardized measure of discounted cash flows	$	36,839	21	%	$	29,102

F-41

Table of Contents

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF THE PARENT

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

PARENT COMPANY CONDENSED BALANCE SHEETS


	December 31
	2021		2020
	(In thousands)
ASSETS
Cash and cash equivalents	$	83,093	$	85,365
Accounts receivable from affiliates	—		495

Other current assets	17,578		20,648
Investment in subsidiaries	268,720		211,468
Property, plant and equipment, net	57		110
Other non-current assets	4,885		5,890
Total Assets	$	374,333	$	323,976
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	3,865	$	3,242
Current intercompany accounts payable, net	637		2,337

Note payable to Bellaire	16,750		16,750
Other non-current liabilities	965		1,023
Stockholders’ equity	352,116		300,624
Total Liabilities and Stockholders’ Equity	$	374,333	$	323,976

See Notes to Parent Company Condensed Financial Statements.

F-42

Table of Contents

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF THE PARENT

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

PARENT COMPANY CONDENSED STATEMENTS OF COMPREHENSIVE INCOME


	Year Ended December 31
	2021		2020
	(In thousands)
Expense (income):
Intercompany interest expense	$	1,172	$	1,178
Other, net	(336)		(1,003)
	836		175
Administrative and general expenses	4,300		5,658
Loss before income taxes	(5,136)		(5,833)
Income tax (benefit) provision	(463)		2,419
Net loss before equity in earnings of subsidiaries	(4,673)		(8,252)
Equity in earnings of subsidiaries	52,798		23,045
Net income	48,125		14,793
Current period pension and postretirement plan adjustment, net of $864 tax expense and $213 tax benefit in 2021 and 2020, respectively	2,851		(697)
Reclassification of pension and postretirement adjustments into earnings, net of $170 and $129 tax benefit in 2021 and 2020, respectively	572		435
Total other comprehensive income	3,423		(262)
Comprehensive Income	$	51,548	$	14,531

See Notes to Parent Company Condensed Financial Statements.

F-43

Table of Contents

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF THE PARENT

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

PARENT COMPANY CONDENSED STATEMENTS OF CASH FLOWS


	Year Ended December 31
	2021		2020
	(In thousands)
Operating Activities
Net income	$	48,125	$	14,793
Equity in earnings of subsidiaries	52,798		23,045
Parent company only net loss	(4,673)		(8,252)
Net changes related to operating activities	8,018		(22,822)
Net cash provided by (used for) operating activities	3,345		(31,074)
Investing Activities


Net cash used for investing activities	—		—
Financing Activities
Dividends received from subsidiaries	—		3,000
Notes payable to Bellaire	—		(200)
Purchase of treasury shares	—		(1,002)
Cash dividends paid	(5,617)		(5,375)

Net cash used for financing activities	(5,617)		(3,577)
Cash and cash equivalents
Decrease for the period	(2,272)		(34,651)
Balance at the beginning of the period	85,365		120,016
Balance at the end of the period	$	83,093	$	85,365

See Notes to Parent Company Condensed Financial Statements.

F-44

Table of Contents

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF THE PARENT

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

NOTES TO PARENT COMPANY CONDENSED FINANCIAL STATEMENTS

FOR THE YEAR ENDED DECEMBER 31, 2021 AND 2020

The notes to Consolidated Financial Statements, incorporated in Item 15 of this Form 10-K, are hereby incorporated by reference into these Notes to Parent Company Condensed Financial Statements.

NOTE A — ACCOUNTING POLICIES

In the Parent Company Condensed Financial Statements, NACCO's investment in subsidiaries is stated at cost plus equity in undistributed earnings of subsidiaries since the date of acquisition. NACCO's share of net income of unconsolidated subsidiaries is included in net income using the equity method. Parent Company financial statements should be read in conjunction with the Company's consolidated financial statements.

NOTE B — LONG-TERM OBLIGATIONS AND GUARANTEES

It is NACCO's policy not to guarantee the debt of NACoal.

NOTE C — UNRESTRICTED CASH

The amount of unrestricted cash available to NACCO, included in Investment in subsidiaries, was $1.2 million at December 31, 2021 and was in addition to the $83.1 million of cash included in the Parent Company Condensed Balance Sheet at December 31, 2021.

F-45

Table of Contents

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

NACCO INDUSTRIES, INC. AND SUBSIDIARIES

YEAR ENDED DECEMBER 31, 2021 AND 2020


			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts — Describe		Deductions — Describe		Balance at End of Period (A)
(In thousands)
2021
Reserves deducted from asset accounts:
Deferred tax valuation allowances	$	11,549	$	146	$	—	$	—	$	11,695
2020
Reserves deducted from asset accounts:
Deferred tax valuation allowances	$	12,296	$	(747)	$	—	$	—	$	11,549

(A)Balances which are not required to be presented and those which are immaterial have been omitted.

F-46

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine

Beulah, North Dakota

Effective Date: December 31, 2021

Report Date: February 14, 2022

Report Prepared by:

The Coteau Properties Company

204 County Road 15

Beulah, ND 58523

Signed by Qualified Persons:

Kendra Braun, PE

Joe Spiekermeier, PE

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

TABLE OF CONTENTS


TABLE OF CONTENTS			2
LIST OF TABLES AND FIGURES			6
SIGNATURE AND REPORT DATE			7
1.0	EXECUTIVE SUMMARY		10
		PROPERTY DESCRIPTION AND OWNERSHIP	10
		GEOLOGY AND MINERALIZATION	10
		STATUS OF EXPLORATION	11
		DEVELOPMENT AND OPERATIONS	11
		MINERAL RESOURCE ESTIMATE	11
		MINERAL RESERVE ESTIMATE	12
		CAPITAL AND OPERATING COSTS	12
		ECONOMIC ASSESSMENT	12
		PERMITTING REQUIREMENTS	13
		QUALIFIED PERSON’S CONCLUSION AND RECOMMENDATIONS	13
2.0	INTRODUCTION		14
3.0	PROPERTY DESCRIPTION		17
	3.1	PROPERTY LOCATION	17
	3.2	PROPERTY AREA AND OWNERSHIP	19
	3.3	LEASES AND MINERAL RIGHTS	19
	3.4	SIGNIFICANT ENCUMBRANCES TO THE PROPERTY	32
	3.5	SIGNIFICANT FACTORS AND RISKS	32
	3.6	REGISTRANT ROYALTIES AND INTERESTS	33
4.0	ACCESSIBILITY, CLIMATE, LOCAL RESOURCES, INFRASTRUCTURE, AND PHYSIOGRAPHY		34
	4.1	PHYSIOGRAPHY, TOPOGRAPHY AND VEGETATION	34
	4.2	ACCESSIBILITY	34
	4.3	CLIMATE	34
	4.4	LOCAL RESOURCES AND INFRASTRUCTURE	35
5.0	HISTORY OF THE PROPERTY		36
	5.1	PREVIOUS OPERATIONS	36
	5.2	EXPLORATION AND DEVELOPMENT HISTORY	36
6.0	GEOLOGICAL SETTING, MINERALIZATION AND DEPOSITION		37
	6.1	GEOLOGY	37
		REGIONAL GEOLOGY	37
	6.2	LOCAL GEOLOGY	40
7.0	EXPLORATION		43
	7.1	EXPLORATION	43
	7.2	DRILLING EXPLORATION	43
		DRILLING TYPE AND EXTENT	43

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022


		GENERAL DRILLING PROCEDURES	43
		DRILLING EXPLORATION PROGRAMS	44
		QUALIFIED PERSON’S OPINION ON DRILLING EXPLORATION	46
		FACTORS THAT CAN AFFECT THE ACCURACY AND RELIABILITY OF THE DRILLING RESULTS	46
	7.3	HYDROGEOLOGIC CHARACTERIZATION	46
		SURFACE WATER	46
		GROUNDWATER	47
		QUALIFED PERSON OPINION – HYDROGEOLOGIC CHARACTERIZATION	48
	7.4	GEOTECHNICAL STUDIES	48
		EARLY GEOTECHNICAL STUDIES	48
		QUALIFED PERSON OPINION – GEOTECHNICAL STUDIES	51
8.0	SAMPLE PREPARATION, ANALYSES, AND SECURITY		53
	8.1	SAMPLE COLLECTION AND SHIPMENT	53
	8.2	SAMPLE PREPARATION AND ANALYSIS	54
	8.3	QUALITY CONTROL PROCEDURES	55
	8.4	QUALIFIED PERSON’S STATEMENT ON THE ADEQUACY OF SAMPLE PREPARATION, SECURITY AND ANALYTICAL PROCEEDURES	56
9.0	DATA VERIFICATION		57
		9.1 DATA VERIFICATION OF DRILL HOLE DATA AND GEOLOGIC (MINERAL RESOURCE) MODEL AND MINERAL RESERVES	57
		9.2 LIMITATIONS ON DATA VERIFICATION	58
		9.3 QUALIFIED PERSON’S STATEMENT OF ADEQUACY OF DATA	58
10.0	MINERAL PROCESSING		60
11.0	MINERAL RESOURCE ESTIMATES		61
	11.1	KEY ASSUMPTIONS, PARAMETERS, AND METHODS	61
		HORIZONS	61
		QUALITY PARAMETERS AND DENSITY DETERMINATION	61
		MODELING PROCESS	62
		JUSTIFICATION OF MODELING METHODS	63
		LIMITS AND CONSTRAINTS ON THE MINERAL RESOURCE ESTIMATES	63
		GENERATION OF PIT SHELLS FOR MINERAL RESOURCE ESTIMATES	64
		MINERAL RESOURCE CLASSIFICATION AND UNCERTAINTY	65
	11.2	MINERAL RESOURCE ESTIMATES	66
		BASIS FOR MINERAL RESOURCE ESTIMATE	66
		MINERAL RESOURCE STATEMENT	66
	11.3	CUT-OFF QUALITY, ASSUMED COST AND SALES PRICE	67
	11.4	QUALIFIED PERSONS CLASSIFICATION OF MINERAL RESOURCES	67
	11.5	UNCERTAINTY IN THE MINERAL RESOURCE ESTIMATES	67
	11.6	QUALIFIED PERSON’S POTENTIAL INFLUENCES AFFECTING MINERAL RESOURCE ESTIMATES	67

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022


12.0	MINERAL RESERVE ESTIMATES		68
	12.1	KEY ASSUMPTIONS, PARAMETERS, AND METHODS	68
	12.2	MINERAL RESERVE ESTIMATES	69
		BASIS FOR MINERAL RESERVE ESTIMATE	69
	12.3	CUT-OFF QUALITY AND SALES PRICE	70
	12.4	MINERAL RESERVE STATEMENT	70
	12.5	MULTIPLE COMMODITY MINERAL RESERVE	70
	12.6	QUALIFIED PERSONS OPINION ON RISK FACTORS THAT COULD AFFECT MINERAL RESERVE ESTIMATES	70
13.0	MINING METHODS		72
	13.1	ANNUAL AND TOTAL LIGNITE PRODUCTION	72
	13.2	TYPE AND GENERAL MINING METHOD	72
	13.3	RUN OF MINE TONNAGES	78
	13.4	ENGINEERING STUDIES – DESIGN PARAMETERS	79
		PIT DESIGN	79
		SPOIL STABILITY STUDIES	84
	13.5	HAUL ROADS, RAMPS AND DRAGLINE WALKWAYS	88
	13.6	PERSONNEL AND MAJOR EQUIPMENT	89
14.0	PROCESSING AND RECOVERY METHODS		91
15.0	INFRASTRUCTURE		92
16.0	MARKET STUDIES		93
	16.1	MARKETS	93
	16.2	MATERIAL CONTRACTS	93
17.0	ENVIRONMENTAL STUDIES, PERMITTING, AND PLANS, NEGOTIATIONS, OR AGREEMENTS WITH LOCAL INDIVIDUALS OR GROUPS		94
	17.1	ENVIRONMENTAL AND BASELINE STUDIES	94
	17.2	WASTE DISPOSAL, SITE MONITORING, AND WATER MANAGEMENT	94
		WASTE DISPOSAL	94
		SITE MONITORING	94
		WATER MANAGEMENT	95
	17.3	PERMITS	95
		PERMIT STATUS	95
	17.4	RECLAMATION BOND REQUIREMENTS	99
	17.5	PLANS, NEGOTIATIONS, OR AGREEMENTS WITH LOCAL INDIVIDUALS OR GROUPS	99
	17.6	MINE CLOSURE PLANS	99
	17.7	QUALIFIED PERSON’S OPINION OF ADEQUACY OF CURRENT PLANS	99
	17.8	DESCRIPTION OF ANY COMMITMENTS TO ENSURE LOCAL PROCUREMENT AND HIRING	99
18.0	CAPITAL AND OPERATING COSTS		100
	18.1	OPERATING COSTS	100

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022


	18.2	CAPITAL COSTS	101
19.0	ECONOMIC ANALYSIS		102
	19.1	KEY ASSUMPTIONS, PARAMETERS AND METHODS	102
	19.2	ANNUAL CASH FLOWS	102
	19.3	SENSITIVITY ANALYSIS	103
20.0	ADJACENT PROPERTIES		104
21.0	OTHER RELEVANT DATA AND INFORMATION		105
22.0	INTERPRETATIONS AND CONCLUSIONS		106
23.0	RECOMMENDATIONS		107
24.0	ADDITIONAL REFERENCES		108
25.0	RELIANCE ON INFORMATION PROVIDED BY THE REGISTRANT		109

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

LIST OF TABLES AND FIGURES

LIST OF FIGURES

FIGURE 3.1. LOCATION OF THE FREEDOM MINE

FIGURE 6.1. GEOLOGIC AND TOPOGRAPHIC BEDROCK MAP OF NORTH DAKOTA (BLUEMLE, 1983)

FIGURE 6.2. STRATIGRAPHIC COLUMN OF THE FREEDOM MINE

FIGURE 6.3. GEOLOGIC CROSS SECTION B-B’, NACT-0401 PERMIT AREA*

FIGURE 7.1. LOCATION OF DRILL HOLES*

FIGURE 7.2. EXISTING MONITORING WELL LOCATION MAP*

FIGURE 7.3. DESTROYED MONITORING WELL LOCATION MAP*

FIGURE 7.4. CERTIFIED WELLS AND SPRINGS LOCATION MAP*

FIGURE 7.5. LOCATION OF GEOTECHNICAL BORINGS (NACOAL, 1981)

FIGURE 8.1. NACOAL 2020 ROUND ROBIN PROGRAM SUMMARY. (NACOAL, 2020)

FIGURE 12.1. LIFE OF MINE MAP*

FIGURE 13.1. RANGE DIAGRAM – SINGLE-PASS METHOD WITH TRUCK/SHOVEL PRE-BENCH

FIGURE 13.2. RANGE DIAGRAM – SINGLE-PASS METHOD WITH DRAGLINE CHOP CUT

FIGURE 13.3. RANGE DIAGRAM – SPOIL-SIDE METHOD STEP 1

FIGURE 13.4. RANGE DIAGRAM – SPOIL-SIDE METHOD STEP 2

FIGURE 13.5. 45 DEGREE HIGHWALL FACTORS OF SAFETY

FIGURE 13.6. 55 DEGREE HIGHWALL FACTORS OF SAFETY

FIGURE 13.7. 60 DEGREE HIGHWALL FACTORS OF SAFETY

FIGURE 13.8. STABILITY NOMOGRAPH FOR CLAYSTONE SPOIL

FIGURE 13.9. MODELED CIRCULAR (ROTATIONAL) FAILURE WITH FACTOR OF SAFETY EQUAL TO 0.987 (BARR ENGINEERING, 2011 )

FIGURE 13.10 MODELED BLOCK FAILURE WITH FACTOR OF SAFETY EQUAL TO 0.931 (BARR ENGINEERING, 2011 )

FIGURE 13.11 DESIGN PARAMETERS FOR GOOD FLOOR CONDITIONS

FIGURE 13.12 DESIGN PARAMETERS FOR POOR FLOOR CONDITIONS

FIGURE 13.13 TYPICAL HAUL ROAD CROSS-SECTION

FIGURE 15.1 INFRASTRUCTURE MAP*

* FIGURES ARE LOCATED IN THE SUPPLEMENTAL FIGURES ATTACHMENT

LIST OF TABLES

TABLE 1.1 MINERAL RESOURCE ESTIMATES

TABLE 1.2 MINERAL RESERVE ESTIMATES

TABLE 3.1 IDENTIFICATION OF LEASES

TABLE 3.2 IDENTIFICATION OF ACQUISITIONS

TABLE 7.1 CONSOL AND BCS EARLY DRILLING EXPLORATION SUMMARY

TABLE 8.1 LIST OF ASTM STANDARDS FOR MVTL

TABLE 11.1 STRATIGRAPHIC HORIZONS

TABLE 11.2 UNIT COSTS-MINERAL RESOURCE ESTIMATION PARAMETERS

TABLE 11.3 MINERAL RESOURCE CATEGORY DISTANCES

TABLE 11.4 MINERAL RESOURCE ESTIMATES

TABLE 12.1 MINERAL RESERVE ESTIMATES

TABLE 13.1 PROJECTED LIFE OF MINE QUALITY

TABLE 13.2 R-O-M DILUTION PARAMETERS

TABLE 13.3 RECOVERY RATES BY SEAM

TABLE 18.1 COST ASSUMPTIONS

TABLE 18.2 COST OF COAL

TABLE 18.3 CAPITAL COSTS

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

SIGNATURE AND REPORT DATE

CERTIFICATE OF QUALIFIED PERSON JOSEPH A. SPIEKERMEIER

(a)I am the Engineering Manager at The Coteau Properties Company Freedom Mine in Beulah, ND; a position I have held since 2018, prior to that I was a Mining Engineer at Coteau since 2002.

(b)This certificate applies to the Technical Report Summary titled, “SEC S-K 1300 Technical Report Summary, The Coteau Properties Company – Freedom Mine, Beulah, North Dakota.

(c)I am a Qualified Person (QP) for the purpose of SEC S-K 1300. My qualifications as a qualified person are as follows:

a.I am a graduate of South Dakota School of Mines and Technology with a Bachelor of Science in Mining Engineering in 2000.

b.I am a Professional Engineer of the state of North Dakota (License Number PE-5756).

c.My relevant experience of over 21 years, for the purpose of the Technical Report Summary, includes 4 years of operating experience and 17 years in various technical roles, all of which have been in the coal industry.

d.I am currently employed by The Coteau Properties Company at the Freedom Mine where I conduct personal inspections of each mining area on a regular basis described in this Technical Report Summary.

e.I am responsible for the sections listed in Table 0.0 of the Technical Report.

f.I have read SEC S-K 1300 Technical Report Summary requirements. The part of the Technical Report Summary for which I am responsible has been prepared in compliance with this requirement.

g.At the effective date of the Technical Report Summary, to the best of my knowledge, information, and belief, the parts of the Technical Report Summary for which I am responsible, contains all scientific and technical information that is required to be disclosed to make the Technical Report Summary not misleading.

h.I consent to the filing of the Technical Report Summary as an exhibit to NACCO Industries, Inc.’s annual report. I also consent to the use of any quotes or summaries in that annual report to the extent they pertain to the Technical Report Summary sections for which I am responsible.

Dated this 14th day of February, 2022

Joseph A. Spiekermeier

The Coteau Properties Company

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

CERTIFICATE OF QUALIFIED PERSON KENDRA R. BRAUN

(d)I am a Geological Engineer at The Coteau Properties Company Freedom Mine in Beulah, ND; a position I have held since my hire in 2009.

(e)This certificate applies to the Technical Report Summary titled, “SEC S-K 1300 Technical Report Summary, The Coteau Properties Company – Freedom Mine, Beulah, North Dakota.

(f)I am a Qualified Person (QP) for the purpose of SEC S-K 1300. My qualifications as a qualified person are as follows:

a.I am a graduate of South Dakota School of Mines and Technology with a Bachelor of Science in Geological Engineering in 2009.

b.I am a Professional Engineer of the state of North Dakota (License Number PE-9807).

c.My relevant experience of over 12 years, for the purpose of the Technical Report Summary, includes exploration, mine geology and various technical roles in the coal industry.

d.I am currently employed by The Coteau Properties Company at the Freedom Mine where I oversee the drilling explorations programs at the mine and conduct personal inspections of each mining area on a regular basis described in this Technical Report Summary.

e.I am responsible for the sections listed in Table 0.0 of the Technical Report.

f.I have read SEC S-K 1300 Technical Report Summary requirements. The part of the Technical Report Summary for which I am responsible has been prepared in compliance with this requirement.

Dated this 14th day of February, 2022

Kendra R. Braun

The Coteau Properties Company

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

The effective date of this Technical Report Summary is December 31, 2021.


QP Name	Sections Responsible For	Signature
Joseph A. Spiekermeier	1, 2, 3, 4, 9, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 25
Kendra R. Braun	2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 17, 22, 23, 24, 25

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

1.0 EXECUTIVE SUMMARY

This Technical Report Summary (TRS) was prepared for The Coteau Properties Company (Coteau) to report Mineral Resources and Mineral Reserves for the Freedom Mine in Mercer County, North Dakota.

PROPERTY DESCRIPTION AND OWNERSHIP

NACCO Industries (NACCO), through a portfolio of mining and natural resources businesses, operates under three business segments: Coal Mining, North American Mining and Minerals Management. The Coal Mining segment operates surface coal mines under long-term contracts with power generation companies and an activated carbon producer pursuant to a service-based business model. Coal is surface-mined in North Dakota, Texas, Mississippi and Louisiana. Each mine is fully integrated with its customer's operations.

The Coteau Properties Company (Coteau), a subsidiary of The North American Coal Corporation (NACoal) is the owner and operator of the Freedom Mine, an active lignite surface mining operation in production status. NACoal is a wholly-owned subsidiary of NACCO. All production from the Freedom Mine is delivered to Dakota Coal Company (DCC), a wholly owned subsidiary of Basin Electric Power Cooperative (BEPC) under a long-term lignite sales agreement (LSA). Although the term of the existing lignite sales agreement terminates in 2027, the term may be extended for two additional periods of five years, or until 2037, at the option of Coteau. DCC then sells the coal to the Dakota Gasification Company’s Great Plains Synfuels Plant (DGC), Antelope Valley Station (AVS) and Leland Olds Station (LOS), all of which are operated by affiliates of BEPC. DGC is a coal gasification plant that manufactures synthetic natural gas and produces fertilizers, solvents, phenol, carbon dioxide, and other chemical products for sale. AVS and LOS are mine-mouth coal-fired power generation facilities.

Coteau provides mining services to DCC. DCC is Coteau’s only customer under an all-requirements cost-plus management fee LSA.

There have been no previous owners or operators of the Freedom Mine.

Under the LSA, Coteau receives a contractually-agreed fee based on the amount of lignite delivered. While Coteau is responsible for all mine operations, DCC is responsible for funding all mine operating costs and provides all the capital required to build and operate the mine. This contract structure eliminates exposure to spot coal market price fluctuations.

Coteau holds 380 leases granting the right to mine approximately 34,016 acres of coal interests and the right to utilize approximately 23,455 acres of surface interests. In addition, Coteau owns in fee 33,805 acres of surface interests and 4,107 acres of coal interests.

The Freedom Mine is located approximately 7 miles north and 3 miles west of Beulah, North Dakota (ND), in Mercer County, which is approximately 90 miles northwest of Bismarck, ND.

GEOLOGY AND MINERALIZATION

The Freedom Mine is located in the Sentinel Butte Formation of the Fort Union Group which is one of the most prolific lignite-bearing stratum in the state. The most prominent characteristics of the Fort Union Group formations are the cyclical deposition and lateral persistence of the lithologic units, especially the lignite seams. The regional structural geology is fairly consistent. No evidence of any significant faulting has been observed in the region. The lignite seams are gently undulating due to differential compaction of the underlying sediments.

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

STATUS OF EXPLORATION

Substantial information has been gathered during exploration drilling programs within the region since the 1960s. These data sets are the foundation for the characterization of the substrate composition, geometry, and structure of the Freedom Mine lignite deposit prior to mining.

Over 7,800 drill holes including lignite exploratory pilot holes and core holes, overburden continuous cores, geotechnical, and hydrological test holes have been drilled by NACoal, Coteau, Consolidation Coal Company (CONSOL), and Basin Cooperative Services (BCS) in and surrounding the Freedom Mine.

DEVELOPMENT AND OPERATIONS

The Freedom Mine has been a producing mine since 1983. The lignite at the Freedom Mine surface mining operation is recovered using dragline and conventional truck and shovel mining. Mining operations includes; suitable plant growth material (SPGM) removal, replacement and storage, overburden removal, lignite production, and spoil backfill and grading, and reclamation. In the development phase, drainage and water control were established (see Water Management under Section 17.0), and then the required infrastructure consisting of power, mine office and maintenance facilities, lignite stockpile facilities, and roadways were established.

MINERAL RESOURCE ESTIMATE

The Mineral Resources in this TRS have been estimated by applying a series of geologic and physical limits as well as high-level mining and economic constraints. The mining and economic constraints were limited to a level sufficient to support reasonable prospect for economic extraction of the estimated Mineral Resources. Resource pit shells were projected to meet the total tonnage requirements to provide lignite fuel to DCC through 2045 which are the current estimated lives of DGC and AVS. The field was analyzed, and the lowest cost portions of the model needed to match the required tonnage were included in the life-of-mine (LOM) plans. The existing lignite sales agreement between Coteau and DCC is in effect through 2037, therefore any tons within the LOM plan through 2037 are considered a reserve. Coal remaining outside of the existing contract end date is considered a resource.

The QP based the Mineral Resource estimates for the Freedom Mine on a stratigraphic geologic model generated from the verified drilling exploration data.

Mineral Resources classification distances from point of measurement for each class are as follows: Measured – less than 660 feet, Indicated - from 660 feet to 1,320 feet, and Inferred - greater than 1,320 feet. A cut-off grade of $1.70/mmBTU has been applied to the Mineral Resource Estimation. Results of the Mineral Resource Estimation calculations are shown in Table 1.1

The effective date of Mineral Resource estimates is December, 31, 2021.


			Quality
			Calorific Value	Moisture	Ash	Sulfur	Sodium in Ash
Mine	Resource Classification	Tonnage	(Btu/lb)	(wt%)	(wt%)	(wt%)	(wt%)
	Measured	322,310,200	6,779	37.64	7.27	0.89	5.62
Freedom Mine	Indicated	8,188,400	6,776	37.92	7.22	0.90	6.36
	Measured + Indicated	330,498,600	6,778	37.64	7.27	0.89	5.63
	Inferred	15,000	6,463	37.84	9.78	1.02	1.59

Table 1.1. Mineral Resource Estimates

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

MINERAL RESERVE ESTIMATE

The Mineral Reserves in this TRS were determined to be the economically mineable portion of the Measured and Indicated Mineral Resources after the consideration of modifying factors related to the mining process, which convert Measured Resources to Proven Mineral Reserves and Indicated Resources to Probable Mineral Reserves. Inferred Mineral Resources were not considered for Mineral Reserves. A cut-off grade of $1.55/mmBTU has been applied to the Measured and Indicated Resources to upgrade these resources into Proven and Probable Reserves. Mineral Reserves Estimates have been calculated and are shown in Table 1.2.

The effective date of Mineral Reserve estimates is December, 31, 2021.


			Quality
			Calorific Value	Moisture	Ash	Sulfur	Sodium in Ash
Mine	Reserve Classification	Tonnage	(Btu/lb)	(wt%)	(wt%)	(wt%)	(wt%)
	Proven	253,946,500	6,779	37.70	7.19	0.89	5.12
Freedom Mine	Probable	3,552,300	6,756	38.29	6.78	0.84	5.40
	Total	257,498,800	6,779	37.71	7.19	0.88	5.12

Table 1.2. Mineral Reserve Estimates

CAPITAL AND OPERATING COSTS

Annual production costs were estimated to satisfy the contractual terms of the LSA. All costs were estimated based on the most recent LOM tonnage requirement provided by DCC in 2009.

The model used to estimate the operating costs is based on historical costs and performance measures that have been maintained by Coteau since its inception. These costs are reviewed and verified on an annual basis to account for changes in site conditions or the operating plan. This information is then used to estimate the projected costs for the LOM plan until the end of the current LSA in 2037.

Capital costs include equipment expenditures, land acquisition, and additional mine area development costs. All capital costs incurred by Coteau are reimbursed by DCC as required under the terms of the LSA. Should the LSA be extended beyond 2037, additional capital costs would be required and funded by DCC.

ECONOMIC ASSESSMENT

The primary key assumption in determining the economic viability of the Freedom Mine reserves is BEPC’s continued operation of AVS, LOS and DGC and the resultant required annual deliveries. The analysis of economic viability is supported by the existing all-requirements LSA and the LOM plan that supports the LSA. The LSA requires DCC to fund all mine operating costs, including final mine reclamation, and provide all of the capital required to build and operate the mine. This contract structure eliminates exposure to spot coal market price fluctuations.

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

PERMITTING REQUIREMENTS

Coteau currently has all permits in place for the Freedom Mine to operate through 2031. Permit expansions required to extend the life of the mine through 2045, which is the current estimated lives of DGC and AVS, will be acquired as needed. Absent of any regulatory changes out of Coteau’s control, the Qualified Persons (QPs) do not anticipate hurdles for approval of future renewal applications. The QPs base this opinion on the mine’s demonstrated success meeting regulatory requirements. Furthermore, appropriate bonding and closure plans are in place with regulatory entities.

QUALIFIED PERSON’S CONCLUSION AND RECOMMENDATIONS

In the QP’s opinion, the geological data, sampling, modeling, and estimate are carried out in a manner that both represents the data well and mitigates the likelihood of material misrepresentations for the statements of Mineral Resources.

In the QP’s opinion, the operational and mine planning data, LOM Plan, and estimation are carried out in a manner that both represents the data and operational experience and methodology well and mitigates the likelihood of material misrepresentations for the statements of Mineral Reserves.

The regulatory environment is favorable in North Dakota for continued operation of the Freedom Mine. All permits have been acquired for continued operation through 2031. No permitting obstacles are anticipated for the permit renewal cycles.

Recommendations:

•Continued drilling to expand mineral resources and shore up mineral reserves.

•Monitor environmental regulatory changes and effects they may have on project life

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

2.0 INTRODUCTION

This technical report was prepared for Coteau which operates the Freedom Mine.

The purpose for which this technical report summary was prepared is to report Mineral Resources and Mineral Reserves for the Freedom Mine located in Mercer County, North Dakota.

The sources of information and data contained in the technical report or used in its preparations were supplied by Coteau and include data used to produce geologic models, production data, environmental support documents, third-party technical studies, resource and reserve estimates, cost estimates, and economic analyses. A large portion of the technical information is summarized from Surface Mining Permits issued by the North Dakota Public Service Commission (NDPSC). Additional references to specific studies and documents are provided in Section 24.0 of this technical report summary (TRS).

Qualified persons (QPs) are employed by Coteau. As such, inspections are conducted on a regular basis and no individual date of inspection has been identified. Kendra R. Braun is a licensed Professional Engineer, who has direct oversight of the drilling exploration programs, and is directly involved in mine development projects and daily production operations at the Freedom Mine. Joseph A. Spiekermeier is a licensed Professional Engineer who has direct engagement with daily production operations and oversight and management of technical projects as the Engineering Manager, and is directly involved in the development of the LOM finances at the Freedom Mine.

This is the first TRS filed with the United States Securities and Exchange Commission (SEC) in accordance with S-K Subpart 1300 regulations, therefore no preexisting TRS exists with the SEC. Mineral Resource and Reserve estimations prior to December 31, 2021 were reported in accordance with guidance of Industry Guide 7.

This terms of reference for this TRS include

–US English spelling;

–Imperial units of measurement;

–Lignite qualities are presented in weight percent (wt%) and lignite tonnages are present in short tons (2000 lbs);

–Coordinate System is presented in imperial units using the North American Datum 1927 (NAD27), North Dakota State Plane, South Zone;

–Nominal US Dollars as of 2021.

Key Acronyms and definitions for this TRS include:


ANG			American Natural Gas
AR			As-Received Basis
ARO			Asset Retirement Obligation
ASTM			American Society for Testing and Materials
AVS			Antelope Valley Station
Barr			Barr Engineering
BCS			Basin Cooperative Services
BCY			Bank Cubic Yard
BTU			British Thermal Units
BEPC			Basin Electric Power Cooperative
BMPs			Best Management Practices
Century GLS			Century Geophysical Logging Services
COC			Chain of Custody
CONSOL			Consolidation Coal Company
Coteau			The Coteau Properties Company

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022


CRIRSCO			Committee for Mineral Reserves International Reporting Standards
DCC			Dakota Coal Company
DGC			Dakota Gasification Company
EMA			East Mine Area
K			Hydraulic Conductivity
lbs			Pounds
LOM			Life of Mine
LOS			Leland Olds Station
LSA			Lignite Sales Agreement
MA1			Mine Area 1
MA2			Mine Area 2
MA3			Mine Area 3
MA4			Mine Area 4
MAF			Moisture Ash Free
mg/L			Milligrams per Liter
mmBTU			million BTU
mm tons			Million Tons
msl			Mean Sea Level
MVTL			Minnesota Valley Testing Laboratories, Inc.
NACCO			NACCO Industries
NACoal			The North American Coal Corporation
ND			North Dakota
NDCC			North Dakota Century Code
NDDEQ			North Dakota Department of Environmental Quality
NDDOT			North Dakota Department of Transportation
NDPDES			North Dakota Pollutant Discharge Elimination System
NDPSC			North Dakota Public Service Commission
NELAP			National Environmental Laboratory Accreditation Program
NOV			Notice of Violation
OSMRE			United States Department of the Interior, Office of Surface Mining Reclamation Enforcement
PFS			Pre-feasibility Study
QA/QC			Quality Assurance/Quality Control
QP(s)			Qualified Person(s)
R-O-M			Run of Mine
R-O-W			Right of Way
SEC			United States Securities and Exchange Commission
S-K 1300			SEC’s Subpart S-K 1300 (17 CFR 229.1300)
SMCRA			Surface Mining Control and Reclamation Act
SPCC			Spill Prevention, Control, and Countermeasures
SPGM			Suitable Plant Growth Material
TDS			Total Dissolved Solids
TNI			The NELAC Institute
TRS			Technical Report Summary

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022


TSS			Total Suspended Solids
USCS			Unified Soil Classification System
USGS			United States Geological Survey
WMA			West Mine Area

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

3.0 PROPERTY DESCRIPTION

3.1 PROPERTY LOCATION

The Freedom Mine is located approximately 7 miles north and 3 miles west of Beulah, North Dakota (ND), in Mercer County, which is approximately 90 miles northwest of Bismarck, ND. The entrance to the mine is by means of a paved road north of the intersection of State Highway 49 and United States Highway 200. The general location of the Freedom Mine is shown in Figure 3.1 (Location of the Freedom Mine). AVS and DGC are located adjacent to the Freedom Mine.

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

Figure 3.1 Location of the Freedom Mine

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

3.2 PROPERTY AREA AND OWNERSHIP

Coteau, a subsidiary of NACoal, is the owner and operator of the Freedom Mine, an active lignite surface mining operation in production status. NACoal is a wholly-owned subsidiary of NACCO Industries. All production from the mine is delivered to DCC, a wholly owned subsidiary of BEPC. DCC then sells the coal to DGC, AVS, and LOS, all of which are operated by affiliates of BEPC. There have been no previous owners or operators of the Freedom Mine.

The Freedom Mine is broken out into different mine areas, namely Mine Area 1 (MA1), Mine Area 2 (MA2)/East Mine Area (EMA), Mine Area 3 (MA3), Mine Area 4 (MA4), Far East Area, Renner’s Cove, and Dakota Star.

3.3 LEASES AND MINERAL RIGHTS

Coteau holds 380 leases granting the right to mine approximately 34,016 acres of coal interests and the right to utilize about 23,455 acres of surface interests. In addition, Coteau owns in fee about 33,805 acres of surface interests and 4,107 acres of coal interests. The leases and deeds are recorded at the Mercer County courthouse and are a matter of public record. Substantially all of the leases were acquired in the 1970’s and have been replaced with new leases and/or have continuation provisions that generally permit the leases to be continued beyond their fixed terms. The leases obligate Coteau to make payments based on the amount of lignite mined from the subject property. Most royalty rates range from $0.08 - $0.16 per ton of lignite mined. A few leases include annual escalator provisions. Payments also may include surface damage payments and advanced or minimum royalty payments. Production royalties are calculated monthly based on surveys and are generally paid on a quarterly basis, although in certain situations royalties are paid monthly. Table 3.1 Identification of Leases, and Table 3.2 Identification of Acquisitions, shows the name or identifying number of each lease, or sublease, the nature and extent of Coteau’s title to, or interest in, the associated property, and expiration date of each lease. While Coteau’s leases include a primary, or fixed, term (as set forth in Table 3.1), they include continuation provisions that allow for their continuation beyond their primary terms so long as operations and/or reclamation activities are continuing.

Table 3.1 Identification of Leases

Lease Id

Lease Type

Lease Date

Lease Expiration Date

215-01947

Coal Lease

6/1/2006

5/31/2026

2AR-00503

Coal Lease Agreement

10/10/1989

10/9/1999

2AR-00504

Coal Lease Agreement

5/1/1990

4/30/2000

2AR-00505

Coal Lease Agreement

5/1/1990

4/30/2000

2AR-00591

Coal Lease

7/25/1997

6/30/2017

2AR-00597

Surface & Coal Lease Agreement

4/6/2000

4/5/2020

2AR-00598

Surface & Coal Lease Agreement

4/13/2000

4/12/2020

2AR-00599

Surface & Coal Lease Agreement

4/14/2000

4/13/2020

2AR-00600

Surface & Coal Lease Agreement

4/20/2000

4/19/2020

2AR-00601

Surface Lease Agreement

5/10/2000

5/9/2020

2AR-00602

Surface Lease Agreement

5/24/2000

5/23/2020

2AR-00603

Surface & Coal Lease Agreement

8/5/2000

8/4/2020

2AR-00604

Coal Lease Agreement

9/11/2000

9/10/2020

2AR-00606

Surface & Coal Lease Agreement

11/8/2000

11/7/2020

2AR-00612

Surface Lease Agreement

8/20/2001

8/19/2021

2AR-00613

Surface Lease Agreement

9/13/2001

9/12/2011

2AR-00615

Coal Lease Agreement

12/4/2001

12/3/2011

2AR-00616

Coal Lease Agreement

12/10/2001

12/9/2011

2AR-00617

Coal Lease Agreement

12/28/2001

12/27/2011

2AR-00618

Coal Lease

2/28/2002

2/27/2032

2AR-00619

Coal Lease

2/28/2002

2/27/2032

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

2AR-00620

Coal Lease

2/28/2002

2/27/2032

2AR-00621

Coal Lease

2/28/2002

2/27/2032

2AR-00622

Coal Lease

2/28/2002

2/27/2032

2AR-00623

Coal Lease

2/28/2002

2/27/2032

2AR-00628

Surface & Coal Lease Agreement

5/20/2002

5/19/2022

2AR-00632

Surface Lease Agreement

8/28/2002

8/27/2022

2AR-00633

Coal Lease Agreement

3/17/2003

3/16/2013

2AR-00635

Coal Lease

10/11/2004

10/10/2034

2AR-00636

Coal Lease

10/11/2004

10/10/2034

2AR-00637

Coal Lease

10/11/2004

10/10/2034

2AR-00641

Surface & Coal Lease Agreement

5/12/2004

5/11/2014

2AR-00643

Coal Lease Agreement

8/25/2004

8/24/2024

2AR-00644

Coal Lease Agreement

8/25/2004

8/24/2024

2AR-00645

Coal Lease Agreement

8/25/2004

8/24/2024

2AR-01948

Surface Lease Agreement

1/13/2012

1/12/2032

2AR-01949

Coal Lease Agreement

12/6/2013

12/5/2033

2AR-01950

Coal Lease Agreement

12/6/2013

12/5/2033

2AR-01951

Coal Lease Agreement

12/17/2013

12/16/2033

2AR-01952

Coal Lease Agreement

12/31/2013

12/30/2033

2AR-01953

Coal Lease Agreement

3/13/2014

3/12/2034

2AR-01955

Coal Lease Agreement

7/8/2016

7/7/2036

2AR-01957

Coal Lease Agreement

8/15/2016

8/14/2026

2AR-01958

Coal Lease Agreement

9/12/2016

9/11/2026

2AR-01959

Coal Lease Agreement

7/28/2016

7/27/2026

2AR-01960

Surface Lease Agreement

7/6/2018

7/5/2043

2AR-01961

Surface Lease Agreement

12/11/2018

12/10/2043

2AR-01962

Coal Lease Agreement

6/14/2020

6/13/2045

2AR-01963

Coal Lease Agreement

6/16/2020

6/15/2045

2AR-01964

Coal Lease Agreement

6/16/2020

6/15/2045

2AR-01965

Coal Lease Agreement

7/2/2020

7/1/2045

2AR-01966

Coal Lease Agreement

7/2/2020

7/1/2045

2AR-01967

Coal Lease Agreement

7/6/2020

7/5/2045

2AR-01968

Coal Lease Agreement

7/7/2020

7/6/2045

2AR-01969

Coal Lease Agreement

7/7/2020

7/6/2045

2AR-01970

Coal Lease Agreement

7/7/2020

7/6/2045

2AR-01971

Coal Lease Agreement

7/8/2020

7/7/2045

2AR-01972

Coal Lease Agreement

7/24/2020

7/23/2045

2AR-01973

Coal Lease Agreement

7/25/2020

7/24/2045

2AR-01974

Coal Lease Agreement

8/10/2020

8/9/2045

2AR-01975

Coal Lease Agreement

8/13/2020

8/12/2045

2AR-01976

Coal Lease Agreement

8/14/2020

8/13/2045

2AR-01977

Coal Lease Agreement

8/17/2020

8/16/2045

2AR-01978

Coal Lease Agreement

8/18/2020

8/17/2045

2AR-01979

Coal Lease Agreement

8/24/2020

8/23/2045

2AR-01980

Coal Lease Agreement

8/25/2020

8/24/2045

2AR-01981

Coal Lease Agreement

8/26/2020

8/25/2045

2AR-01982

Coal Lease Agreement

8/26/2020

8/25/2045

2AR-01983

Coal Lease Agreement

8/27/2020

8/26/2045

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

2AR-01984

Coal Lease Agreement

9/2/2020

9/1/2045

2AR-01985

Coal Lease Agreement

8/23/2020

8/22/2045

2AR-01986

Coal Lease Agreement

9/2/2020

9/1/2045

2AR-01987

Coal Lease Agreement

9/8/2020

9/7/2045

2AR-01988

Coal Lease Agreement

9/8/2020

9/7/2045

2AR-01989

Coal Lease Agreement

9/3/2020

9/2/2045

2AR-01990

Coal Lease Agreement

9/15/2020

9/14/2045

2AR-01991

Coal Lease Agreement

9/16/2020

9/15/2045

2AR-01992

Coal Lease Agreement

9/15/2020

9/14/2045

2AR-01993

Surface & Coal Lease Agreement

9/16/2020

9/15/2045

2AR-01994

Surface & Coal Lease Agreement

9/15/2020

9/14/2045

2AR-01995

Coal Lease Agreement

9/16/2020

9/15/2045

2AR-01996

Surface & Coal Lease Agreement

9/15/2020

9/14/2045

2AR-01997

Surface & Coal Lease Agreement

9/15/2020

9/14/2045

2AR-01998

Coal Lease Agreement

10/6/2020

10/5/2045

2AR-01999

Coal Lease Agreement

10/6/2020

10/5/2045

2AR-06000

Coal Lease Agreement

10/14/2020

10/13/2045

2AR-06001

Coal Lease Agreement

10/15/2020

10/14/2045

2AR-06002

Coal Lease Agreement

10/16/2020

10/15/2045

2AR-06003

Coal Lease Agreement

11/2/2020

11/1/2045

2AR-06004

Coal Lease Agreement

11/7/2020

11/6/2045

2AR-06005

Coal Lease Agreement

11/18/2020

11/17/2045

2AR-06006

Coal Lease Agreement

12/22/2020

12/21/2045

2AR-06007

Coal Lease Agreement

12/23/2020

12/22/2045

2AR-06008

Coal Lease Agreement

12/28/2020

12/27/2045

2AR-06009

Coal Lease Agreement

12/31/2020

12/30/2045

2AR-06010

Coal Lease Agreement

1/4/2021

1/3/2046

2AR-06011

Coal Lease Agreement

1/11/2021

1/10/2046

2AR-06012

Coal Lease Agreement

1/12/2021

1/11/2046

2AR-06013

Coal Lease Agreement

1/14/2021

1/13/2046

2AR-06014

Coal Lease Agreement

1/15/2021

1/14/2046

2AR-06015

Coal Lease Agreement

1/15/2021

1/14/2046

2AR-06016

Coal Lease Agreement

1/16/2021

1/15/2046

2AR-06017

Coal Lease Agreement

1/19/2021

1/18/2046

2AR-06018

Coal Lease Agreement

1/25/2021

1/24/2046

2AR-06019

Coal Lease Agreement

1/30/2021

1/29/2046

2AR-06020

Coal Lease Agreement

5/12/2021

5/11/2046

2AR-06021

Coal Lease Agreement

7/2/2021

7/1/2046

2AR-06022

Coal Lease Agreement

9/2/2021

9/1/2046

2AR-06023

Surface & Coal Lease Agreement

9/13/2021

9/12/2046

2AR-06024

Coal Lease Agreement

9/28/2021

9/27/2046

2DS-00506

Surface & Coal Lease Agreement

12/28/1990

12/27/2010

2DS-00510

Coal Lease

11/26/1969

11/25/1994

2DS-00512

Coal Lease

5/5/1971

5/4/1996

2DS-00514

Coal Lease

11/27/1972

11/26/1997

2DS-00516

Coal Lease

8/1/1973

7/31/1998

2DS-00517

Coal Lease

8/1/1973

7/31/1998

2DS-00518

Coal Lease

4/9/1974

4/8/2014

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

2DS-00531

Coal Lease

8/27/1970

8/26/2010

2DS-00532

Coal Lease

8/27/1970

8/26/2010

2DS-00534

Coal Mining Lease

8/27/1973

8/26/1998

2DS-00535

Coal Lease

4/29/1971

4/28/2031

2DS-00536

Coal Lease

8/13/1970

8/12/2010

2DS-00537

Coal Lease

8/13/1970

8/12/2010

2DS-00538

Coal Lease

8/14/1970

8/13/2010

2DS-00539

Coal Lease

9/5/1970

9/4/2010

2DS-00541

Coal Lease

3/27/1974

3/26/2014

2DS-00542

Exploration Contract & Coal Lease

1/14/1974

1/13/2015

2DS-00549

Coal Lease Agreement

9/12/1991

9/11/2011

2DS-00550

Coal Lease Agreement

9/12/1991

9/11/2011

2DS-00551

Coal Lease Agreement

9/12/1991

9/11/2011

2DS-00552

Coal Lease Agreement

9/12/1991

9/11/2011

2DS-00553

Coal Lease

12/19/1991

12/18/2001

2DS-00554

Coal Lease

12/19/1991

12/18/2001

2DS-00555

Coal Lease

12/19/1991

12/18/2001

2DS-00556

Coal Lease

12/19/1991

12/18/2001

2DS-00562

Surface & Coal Lease Agreement

6/22/1993

6/21/2013

2DS-00567

Coal Lease

8/2/1973

8/1/1998

2DS-00571

Surface & Coal Lease Agreement

12/8/1994

12/7/2004

2DS-00572

Exploration Contract & Coal Lease

4/2/1974

4/1/1995

2DS-00573

Coal Lease

5/20/1971

5/19/2021

2DS-00574

Coal Lease

5/25/1971

5/24/2011

2DS-00575

Coal Lease

8/14/1970

8/13/2010

2DS-00576

Exploration Contract & Coal Lease

10/10/1973

10/9/2014

2DS-00577

Exploration Contract & Coal Lease

9/5/1973

9/4/2014

2DS-00580

Exploration Contract & Coal Lease

8/25/1973

8/24/2014

2DS-00581

Exploration Contract & Coal Lease

8/30/1973

8/29/2004

2DS-00583

Coal Lease

6/18/1971

6/17/2021

2DS-00584

Coal Lease

1/29/1973

1/28/1998

2DS-00593

Coal Lease Agreement

6/7/1999

6/6/2019

2DS-00594

Coal Lease Agreement

6/11/1999

6/10/2019

2DS-00595

Coal Lease Agreement

6/22/1999

6/21/2019

2DS-00596

Surface & Coal Lease Agreement

6/21/1999

6/20/2019

2DS-00634

Coal Lease Agreement

3/13/2003

3/12/2013

2DS-00642

Coal Lease

10/11/2004

10/10/2034

2FE-00100

Coal Lease

8/30/2017

8/29/2042

2FE-00101

Coal Lease Agreement

8/30/2017

8/29/2042

2FE-00102

Surface Lease

8/30/2017

8/29/2042

2FE-00103

Surface & Coal Lease Agreement

9/11/2017

9/10/2042

2FE-00104

Surface & Coal Lease Agreement

11/28/2017

11/27/2042

2FE-00105

Surface & Coal Lease Agreement

1/29/2018

1/28/2043

2FE-00106

Surface Lease Agreement

2/22/2018

2/21/2043

2FE-00107

Surface Lease Agreement

3/8/2018

3/7/2043

2FE-00108

Surface & Coal Lease Agreement

4/18/2018

4/17/2043

2FE-00109

Surface & Coal Lease Agreement

4/18/2018

4/17/2043

2FE-00110

Surface Lease Agreement

5/11/2018

5/10/2043

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

2FE-00111

Surface & Coal Lease Agreement

5/11/2018

5/10/2043

2FE-00112

Surface & Coal Lease Agreement

5/31/2018

5/30/2043

2FE-00113

Surface & Coal Lease Agreement

6/12/2018

6/11/2043

2FE-00114

Surface & Coal Lease Agreement

4/12/2018

4/11/2043

2FE-00115

Surface & Coal Lease Agreement

7/10/2018

7/9/2043

2FE-00116

Surface Lease Agreement

9/9/2018

9/8/2043

2FE-00117

Surface & Coal Lease Agreement

8/15/2018

8/14/2043

2FE-00118

Coal Lease Agreement

8/28/2018

8/27/2043

2FE-00119

Coal Lease Agreement

9/4/2018

9/3/2043

2FE-00120

Surface & Coal Lease Agreement

10/3/2018

10/2/2043

2FE-00121

Surface & Coal Lease Agreement

10/4/2018

10/3/2043

2FE-00122

Surface & Coal Lease Agreement

10/11/2018

10/10/2043

2FE-00123

Coal Lease Agreement

8/15/2018

8/14/2043

2FE-00124

Surface Lease Agreement

11/2/2018

11/1/2043

2FE-00125

Surface & Coal Lease Agreement

11/9/2018

11/8/2043

2FE-00126

Surface & Coal Lease Agreement

11/15/2018

11/14/2043

2FE-00127

Surface & Coal Lease Agreement

11/16/2018

11/15/2043

2FE-00128

Surface & Coal Lease Agreement

12/31/2018

12/30/2043

2FE-00129

Surface & Coal Lease Agreement

3/8/2019

3/7/2044

2FE-00130

Surface & Coal Lease Agreement

3/8/2019

3/7/2044

2FE-00131

Surface & Coal Lease Agreement

8/20/2019

8/19/2044

2FE-00132

Coal Lease Agreement

9/26/2019

9/25/2044

2FE-00133

Surface Lease Agreement

10/18/2019

10/17/2044

2FE-00134

Surface Lease Agreement

10/18/2019

10/17/2044

2FE-00135

Coal Lease Agreement

10/17/2019

10/16/2044

2FE-00136

Surface Lease Agreement

10/18/2019

10/17/2044

2FE-00137

Coal Lease Agreement

10/16/2019

10/15/2044

2FE-00138

Coal Lease Agreement

11/1/2019

10/31/2044

2FE-00139

Coal Lease Agreement

11/4/2019

11/3/2044

2FE-00140

Coal Lease Agreement

11/6/2019

11/5/2044

2FE-00141

Coal Lease Agreement

11/8/2019

11/7/2044

2FE-00142

Coal Lease Agreement

11/6/2019

11/5/2044

2FE-00143

Coal Lease Agreement

11/12/2019

11/11/2044

2FE-00144

Coal Lease Agreement

12/16/2019

12/15/2044

2FE-00145

Coal Lease Agreement

12/24/2019

12/23/2044

2FE-00146

Coal Lease Agreement

12/26/2019

12/25/2044

2FE-00147

Coal Lease Agreement

1/22/2020

1/21/2045

2FE-00148

Coal Lease Agreement

2/18/2020

2/17/2045

2FE-00149

Coal Lease Agreement

2/18/2020

2/17/2045

2FE-00150

Coal Lease Agreement

2/24/2020

2/23/2045

2FE-00151

Coal Lease Agreement

2/25/2020

2/24/2045

2FE-00152

Coal Lease Agreement

3/2/2020

3/1/2045

2FE-00153

Coal Lease Agreement

3/2/2020

3/1/2045

2FE-00154

Coal Lease Agreement

2/18/2020

2/17/2045

2FE-00155

Coal Lease Agreement

3/4/2020

3/3/2045

2FE-00156

Coal Lease Agreement

3/4/2020

3/3/2045

2FE-00157

Coal Lease Agreement

3/13/2020

3/12/2045

2FE-00158

Coal Lease Agreement

3/6/2020

3/5/2045

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

2FE-00159

Coal Lease Agreement

3/24/2020

3/23/2045

2FE-00160

Coal Lease Agreement

3/31/2020

3/30/2045

2FE-00161

Coal Lease Agreement

4/13/2020

4/12/2045

2FE-00162

Coal Lease Agreement

5/2/2020

5/1/2045

2FE-00163

Coal Lease Agreement

5/14/2021

5/13/2046

2FE-00164

Coal Lease Agreement

9/1/2021

8/31/2046

2PR-00607

Surface & Coal Lease Agreement

12/17/2000

12/16/2020

2PR-00611

Surface & Coal Lease Agreement

4/25/2001

4/24/2021

2PR-00614

Coal Lease Agreement

9/9/2001

9/8/2011

2PR-01105

Coal Lease

8/25/1966

8/24/2016

2PR-01107

Coal Lease

7/25/1966

7/24/2006

2PR-01116

Surface Lease

4/24/1965

4/23/2015

2PR-01117

Coal Lease

4/24/1965

4/23/2015

2PR-01119

Coal Lease

5/12/1966

5/11/2016

2PR-01120

Coal Lease

5/12/1966

5/11/2006

2PR-01121

Coal Lease

4/8/1970

4/7/2010

2PR-01122

Coal Lease

10/23/1963

10/22/2003

2PR-01123

Coal Lease

9/11/1965

9/10/2005

2PR-01127

Coal Lease

5/9/1965

5/8/2015

2PR-01128

Coal Lease

9/15/1964

9/14/2004

2PR-01130

Coal Lease

7/29/1971

7/28/2021

2PR-01136

Coal Lease

5/25/1970

5/24/2020

2PR-01138

Coal Lease

5/24/1962

5/23/2012

2PR-01145

Coal Lease

8/13/1970

8/12/2010

2PR-01148

Coal Lease

9/8/1964

9/7/2014

2PR-01149

Lease

9/8/1965

9/7/2015

2PR-01152

Coal Lease

9/18/1964

9/17/2014

2PR-01154

Coal Lease

6/21/1972

6/20/2022

2PR-01155

Coal Lease

8/22/1970

8/21/2020

2PR-01156

Coal Lease

6/17/1971

6/16/2021

2PR-01160

Coal Lease

4/30/1965

4/29/2015

2PR-01166

Surface Lease

9/22/1964

9/21/2044

2PR-01177

Coal Lease

9/18/1964

9/17/2014

2PR-01178

Lease

9/18/1964

9/17/2014

2PR-01204

Coal Lease

6/18/1971

6/17/2021

2PR-01219

Coal Lease

9/18/1964

9/17/2004

2PR-01224

Surface Lease

3/8/1965

3/7/2015

2PR-01225

Surface Lease

3/8/1965

3/7/2015

2PR-01227

Surface Lease

3/8/1965

3/7/2015

2PT-00318

Exploration Contract & Coal Lease

10/25/1982

10/24/2022

2PT-00319

Coal Lease

10/25/1982

10/24/2012

2PT-00320

Coal Lease

10/25/1982

10/24/2012

2PT-00321

Coal Lease

10/25/1982

10/24/2012

2PT-00322

Coal Lease

10/25/1982

10/24/2012

2PT-00323

Coal Lease

10/25/1982

10/24/2012

2PT-00327

Coal Lease

10/29/1982

10/28/2022

2PT-00328

Coal Lease

10/14/1982

10/13/2022

2PT-00329

Coal Lease

10/14/1982

10/13/2022

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

2PT-00330

Coal Lease

10/25/1982

10/24/2012

2PT-00331

Coal Lease

10/29/1982

10/28/2022

2PT-00332

Coal Lease

11/15/1982

11/14/2022

2PT-00333

Coal Lease

11/15/1982

11/14/2022

2PT-00335

Coal Lease

12/22/1982

12/21/2022

2PT-00343

Coal Lease

9/27/1983

9/26/2023

2PT-00610

Surface & Coal Lease Agreement

4/19/2001

4/18/2021

2PT-00627

Surface & Coal Lease Agreement

4/11/2002

4/10/2012

2PT-00629

Coal Lease Agreement

5/20/2002

5/19/2022

2PT-00630

Coal Lease Agreement

6/6/2002

6/5/2012

2PT-00631

Surface & Coal Lease Agreement

8/21/2002

8/20/2022

2PT-00646

Surface & Coal Lease Agreement

7/5/2005

7/4/2015

2PT-00648

Surface & Coal Lease Agreement

1/17/2008

1/16/2028

2PT-01113

Exploration Contract & Coal Lease

8/28/1972

8/27/2013

2PT-01143

Exploration Contract & Coal Lease

9/13/1972

9/12/2013

2PT-01196

Coal Lease

11/13/1969

11/12/1994

2PT-01205

Coal Lease

3/6/1974

3/5/2014

2PT-01206

Coal Lease

3/7/1974

3/6/2014

2PT-01208

Coal Lease

3/13/1974

3/12/2014

2PT-01230

Exploration Contract & Coal Lease

4/6/1981

4/5/2001

2PT-01246

Coal Lease

5/28/1971

5/27/2021

2PT-01249

Coal Lease

5/4/1971

5/3/2021

2PT-01258

Coal Lease

5/25/1971

5/24/2011

2PT-01262

Coal Lease

6/24/1971

6/23/2011

2PT-01265

Coal Lease

5/20/1971

5/19/2021

2PT-01272

Exploration Contract & Coal Lease

10/7/1971

10/6/2012

2PT-01288

Coal Lease

4/1/1974

3/31/2014

2PT-01291

Coal Lease

4/1/1974

3/31/2014

2PT-01293

Coal Lease

4/1/1974

3/31/2014

2PT-01295

Coal Lease

4/1/1974

3/31/2014

2PT-01297

Coal Lease

4/2/1974

4/1/2014

2PT-01298

Coal Mining Lease

8/7/1973

8/6/2003

2PT-01302

Coal Lease

4/2/1974

4/1/2014

2PT-01303

Exploration Contract & Coal Lease

8/1/1973

7/31/2014

2PT-01304

Coal Lease

4/2/1974

4/1/2014

2PT-01307

Exploration Contract & Coal Lease

8/24/1973

8/23/2014

2PT-01312

Coal Lease

4/2/1974

4/1/2014

2PT-01313

Coal Mining Lease

8/17/1973

8/16/2003

2PT-01314

Coal Lease

4/2/1974

4/1/2014

2PT-01315

Coal Lease

4/2/1974

4/1/2014

2PT-01318

Coal Lease

4/2/1974

4/1/2014

2PT-01319

Coal Lease

4/2/1974

4/1/2014

2PT-01320

Coal Lease

4/3/1974

4/2/2014

2PT-01331

Coal Lease

4/24/1974

4/23/2014

2PT-01336

Coal Lease

5/13/1974

5/12/2014

2PT-01339

Coal Mining Lease

8/6/1973

8/5/2013

2PT-01344

Coal Lease

6/4/1971

6/3/1996

2PT-01345

Coal Mining Lease

8/27/1973

8/26/1998

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

2PT-01651

Coal Lease

6/6/1974

6/5/2014

2PT-01652

Exploration Contract & Coal Lease

8/9/1973

8/8/2014

2PT-01660

Coal Mining Lease

8/23/1973

8/22/2013

2PT-01661

Coal Mining Lease

8/23/1973

8/22/2013

2PT-01662

Coal Mining Lease

8/23/1973

8/22/2013

2PT-01663

Exploration Contract & Coal Lease

8/25/1973

8/24/2014

2PT-01667

Coal Mining Lease

8/29/1973

8/28/2013

2PT-01668

Coal Mining Lease

8/23/1973

8/22/2003

2PT-01669

Coal Mining Lease

8/23/1973

8/22/2003

2PT-01671

Coal Mining Lease

8/17/1973

8/16/2003

2PT-01675

Exploration Contract & Coal Lease

8/28/1973

8/27/2014

2PT-01677

Exploration Contract & Coal Lease

8/30/1973

8/29/2004

2PT-01678

Exploration Contract & Coal Lease

8/28/1973

8/27/2014

2PT-01686

Exploration Contract & Coal Lease

8/28/1973

8/27/2014

2PT-01699

Exploration Contract & Coal Lease

8/24/1973

8/23/2014

2PT-01702

Coal Mining Lease

8/17/1973

8/16/2003

2PT-01707

Exploration Contract & Coal Lease

9/5/1973

9/4/2014

2PT-01709

Exploration Contract & Coal Lease

9/5/1973

9/4/2014

2PT-01712

Exploration Contract & Coal Lease

8/29/1973

8/28/2014

2PT-01715

Exploration Contract & Coal Lease

9/4/1973

9/3/2004

2PT-01729

Exploration Contract & Coal Lease

9/14/1973

9/13/1993

2PT-01731

Coal Mining Lease

8/23/1973

8/22/2003

2PT-01740

Exploration Contract & Coal Lease

9/24/1973

9/23/2014

2PT-01743

Exploration Contract & Coal Lease

8/21/1973

8/20/2014

2PT-01747

Exploration Contract & Coal Lease

9/15/1973

9/14/1993

2PT-01755

Exploration Contract & Coal Lease

9/26/1973

9/25/2014

2PT-01757

Exploration Contract & Coal Lease

9/20/1973

9/19/2014

2PT-01758

Exploration Contract & Coal Lease

9/12/1973

9/11/1993

2PT-01759

Exploration Contract & Coal Lease

10/10/1973

10/9/2014

2PT-01763

Exploration Contract & Coal Lease

11/26/1973

11/25/1994

2PT-01769

Lease

8/7/1973

8/6/2023

2PT-01784

Exploration Contract & Coal Lease

9/20/1973

9/19/1993

2PT-01787

Exploration Contract & Coal Lease

10/1/1973

9/30/1994

2PT-01810

Exploration Contract & Coal Lease

9/20/1973

9/19/1993

2PT-01815

Exploration Contract & Coal Lease

2/15/1974

2/14/2015

2PT-01817

Exploration Contract & Coal Lease

3/7/1974

3/6/2015

2PT-01825

Exploration Contract & Coal Lease

4/2/1974

4/1/1995

2PT-01829

Exploration Contract & Coal Lease

3/26/1974

3/25/1995

2PT-01830

Exploration Contract & Coal Lease

3/26/1974

3/25/1995

2PT-01831

Exploration Contract & Coal Lease

3/26/1974

3/25/1994

2PT-01850

Coal Lease

6/24/1974

6/23/1999

2PT-01852

Coal Lease

6/24/1974

6/23/1999

2PT-01880

Exploration Contract & Coal Lease

11/25/1975

11/24/2016

2PT-01881

Exploration Contract & Coal Lease

11/26/1975

11/25/2016

2PT-01882

Exploration Contract & Coal Lease

11/27/1975

11/26/2016

2PT-01883

Exploration Contract & Coal Lease

11/25/1975

11/24/2016

2PT-01893

Exploration Contract & Coal Lease

11/13/1975

11/12/2016

2PT-01906

Exploration Contract & Coal Lease

12/30/1975

12/29/2016

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

2PT-01910

Exploration Contract & Coal Lease

10/29/1976

10/28/2016

2PT-01915

Coal Lease

11/12/1976

11/11/2016

2PT-01917

Exploration Contract & Coal Lease

1/5/1977

1/4/2017

2PT-01918

Coal Lease

1/4/1977

1/3/2017

2PT-01920

Coal Lease

10/29/1969

10/28/1994

2PT-01921

Coal Lease

10/30/1969

10/29/1994

2PT-01942

Coal Lease

5/29/1974

5/28/2014

2PT-01946

Coal Lease

5/24/1971

5/23/2021

2RC-00721

Lease

8/1/1973

7/31/2013

2RC-00723

Coal Mining Lease

7/30/1973

7/29/2013

2RC-00727

Coal Lease

6/22/1971

6/21/2011

2RC-00769

Coal Lease

6/9/1965

6/8/2005

2RC-00770

Coal Mining Lease

8/7/1973

8/6/1993

2RC-00774

Coal Lease

1/11/1974

1/10/1994

2RC-00776

Coal Lease

1/3/1974

1/2/1994

2RC-00827

Coal Lease

8/7/1964

8/6/2004

2RC-00828

Lease

8/7/1964

8/6/2004

2RO-00851

Coal Lease

7/25/1997

6/30/2017

2RO-00858

Surface & Coal Lease Agreement

12/4/1997

12/3/2007

2RO-00871

Surface & Coal Lease Agreement

4/19/2001

4/18/2011

2RO-00883

Coal Lease

5/9/2002

5/31/2022

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

Table 3.2 Identification of Acquisitions

Agreement Id

Agreement Type

Agreement Date

Agreement Expiration Date

213-CTS088

Warranty Deed

5/11/2007

12/31/2099

213-CTS092

Warranty Deed

12/9/2002

12/31/2035

214-CTC002

Mineral Deed

3/31/1975

12/31/2035

234-CTS090

Warranty Deed

9/18/2002

12/31/2035

23R-CTC001

Mineral Deed

8/7/1972

12/31/2099

2-CTC009

Limited Mineral Deed

3/5/1993

12/31/2035

2-CTC010

Mineral Deed

3/10/1994

12/31/2035

2-CTC012

Mineral Deed

12/12/1995

12/31/2099

2-CTC021

Coal Deed

11/6/2009

12/31/2999

2-CTS002

Contract for Deed

12/13/1977

12/31/2099

2-CTS003

Contract for Deed

7/31/1980

12/31/2099

2-CTS007

Quit Claim Deed

12/17/1982

12/31/2999

2-CTS012

Warranty Deed

10/30/1984

12/31/2099

2-CTS015

Warranty Deed

12/30/1987

12/31/2099

2-CTS018

Warranty Deed

6/10/1988

12/31/2099

2-CTS022

Warranty Deed

6/2/1989

12/31/2099

2-CTS033

Warranty Deed

5/6/1992

12/31/2035

2-CTS035

Warranty Deed

5/13/1992

12/31/2035

2-CTS036

Warranty Deed

10/27/1992

12/31/2035

2-CTS063

Warranty Deed

8/15/1997

12/31/2035

2-CTS065

Warranty Deed

12/29/1997

12/31/2035

2-CTS066

Warranty Deed

12/29/1997

12/31/2035

2-CTS077

Warranty Deed

2/29/2000

12/31/2035

2-CTS080

Warranty Deed

5/3/2001

12/31/2099

2-CTS081

Quit Claim Deed

6/20/2001

12/31/2099

2-CTS086

Warranty Deed

11/14/2001

12/31/2099

2-CTS094

Warranty Deed

6/15/2004

12/31/2099

2-CTS109

Warranty Deed

5/16/2005

12/31/2035

2-CTS110

Warranty Deed

1/18/2005

12/31/2035

2-CTS112

Warranty Deed

2/28/2005

12/31/2099

2-CTS113

Warranty Deed

6/11/2005

12/31/2035

2-CTS117

Warranty Deed

12/1/2006

12/31/2099

2-CTS119

Warranty Deed

5/1/2007

12/31/2035

2-CTS120

Warranty Deed

8/17/2005

12/31/2035

2-CTS121

Warranty Deed

10/7/2005

12/31/2099

2-CTS124

Warranty Deed

6/16/2006

12/31/2099

2-CTS125

Warranty Deed

10/19/2006

12/31/2035

2-CTS126

Warranty Deed

6/28/2007

12/31/2035

2-CTS127

Warranty Deed

7/24/2009

12/31/2999

2-CTS128

Warranty Deed

6/22/2009

12/31/2999

2-CTS129

Warranty Deed

4/8/2010

12/31/2999

2-CTS130

Warranty Deed

6/10/2010

12/31/2999

2-CTS131

Warranty Deed

6/10/2010

12/31/2999

2-CTS132

Warranty Deed

12/28/2010

12/31/2099

2-CTS134

Warranty Deed

10/2/2012

12/31/2099

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

2-CTS135

Warranty Deed

7/23/2014

12/31/2099

2-CTS136

Warranty Deed

9/10/2014

12/31/2999

2-CTS137

Warranty Deed

3/11/2015

12/31/2099

2-CTS138

Warranty Deed

7/21/2015

12/31/2099

2-CTS139

Warranty Deed

11/10/2015

12/31/2099

2-CTS140

Warranty Deed

12/21/2016

12/31/2999

2-CTS141

Warranty Deed

5/2/2017

12/31/2099

2-CTS142

Warranty Deed

1/17/2018

12/31/2099

2-CTS143

Warranty Deed

10/5/2018

12/31/2099

2-CTS144

Warranty Deed

10/22/2018

12/31/2099

2-CTS145

Warranty Deed

10/24/2019

12/31/2099

2-CTS146

Warranty Deed

6/11/2021

12/31/2099

2-CTS147

Warranty Deed

12/20/2021

12/31/2099

2D2-CTC019

Bankruptcy Trustee's Deed

6/4/2003

12/31/2035

2D2-CTS060

Warranty Deed

8/4/1997

12/31/2035

2D2-CTS084

Warranty Deed

10/9/2001

12/31/2099

2D2-CTS093

Bankruptcy Trustee's Deed

6/4/2003

12/31/2035

2D-CTC014

Mineral Deed

11/26/1997

12/31/2999

2D-CTC020

Mineral Deed

11/18/2004

11/18/2103

2D-CTS029

Warranty Deed

11/8/1991

12/31/2035

2D-CTS031

Warranty Deed

3/9/1992

12/31/2099

2D-CTS032

Contract for Deed

3/13/1992

12/31/2035

2D-CTS034

Warranty Deed

5/6/1992

12/31/2035

2D-CTS037

Warranty Deed

10/28/1992

12/31/2035

2D-CTS038

Warranty Deed

11/17/1992

12/31/2035

2D-CTS039

Contract for Deed

1/21/1993

12/31/2035

2D-CTS040

Warranty Deed

1/13/1995

12/31/2035

2D-CTS043

Contract for Deed

9/28/1993

12/31/2035

2D-CTS053

Warranty Deed

2/7/1997

12/31/2999

2D-CTS058

Warranty Deed

8/11/1997

12/31/2035

2D-CTS059

Warranty Deed

7/25/1997

12/31/2035

2D-CTS079

Warranty Deed

6/21/2000

12/31/2035

2D-CTS091

Warranty Deed

12/2/2002

12/31/2099

2M1-CTC013

Mineral Deed

3/19/1996

12/31/2035

2M1-CTS123

Warranty Deed

4/7/2006

12/31/2099

2M2-CTC004

Warranty Deed

5/25/1989

12/31/2035

2M2-CTS005

Warranty Deed

9/23/1982

12/31/2035

2M2-CTS006

Contract for Deed

12/22/1982

12/31/2035

2M2-CTS021

Warranty Deed

5/25/1989

12/31/2035

2M2-CTS030

Warranty Deed

1/3/1992

12/31/2035

2M2-CTS041

Warranty Deed

5/4/1993

12/31/2035

2M2-CTS042

Warranty Deed

5/4/1993

12/31/2035

2M2-CTS057

Warranty Deed

8/11/1997

12/31/2035

2M2-CTS061

Warranty Deed

8/18/1997

12/31/2035

2M2-CTS064

Warranty Deed

1/15/1999

12/31/2035

2M2-CTS067

Warranty Deed

3/10/1998

12/31/2035

2M2-CTS085

Warranty Deed

10/10/2001

12/31/2035

2M2-CTS096

Warranty Deed

2/18/2004

12/31/2035

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

2M2-CTS097

Warranty Deed

2/18/2004

12/31/2035

2M2-CTS098

Warranty Deed

4/20/2004

12/31/2099

2M2-CTS099

Warranty Deed

4/20/2004

12/31/2099

2M2-CTS100

Warranty Deed

4/20/2004

12/31/2099

2M2-CTS101

Warranty Deed

4/20/2004

12/31/2099

2M2-CTS102

Warranty Deed

4/20/2004

12/31/2099

2M2-CTS103

Warranty Deed

4/20/2004

12/31/2099

2M2-CTS104

Warranty Deed

4/20/2004

12/31/2099

2M2-CTS105

Warranty Deed

6/23/2004

12/31/2099

2M2-CTS114

Warranty Deed

7/13/2005

12/31/2035

2M2-CTS115

Warranty Deed

7/13/2005

12/31/2035

2M2-CTS116

Warranty Deed

7/15/2005

12/31/2035

2M2-CTS122

Warranty Deed

1/17/2007

12/31/2035

2M3-CTS024

Warranty Deed

9/11/1990

12/31/2035

2M3-CTS051

Warranty Deed

10/21/1996

12/31/2035

2M3-CTS075

Warranty Deed

9/20/1999

12/31/2035

2M3-CTS087

Warranty Deed

11/21/2001

12/31/2035

2M3-CTS095

Warranty Deed

8/26/2003

12/31/2099

2M3-CTS111

Quit Claim Deed

3/2/2005

3/31/2035

2M4-CTC003

Warranty Deed

12/30/1987

12/31/2035

2M4-CTC005

Warranty Deed

8/17/1989

12/31/2035

2M4-CTC006

Mineral Deed

6/29/1990

12/31/2035

2M4-CTC007

Warranty Deed

11/5/1990

12/31/2035

2M4-CTC008

Warranty Deed

5/23/1991

12/31/2035

2M4-CTS001

Warranty Deed

6/30/1977

12/31/2099

2M4-CTS004

Warranty Deed

9/3/1981

12/31/2035

2M4-CTS008

Warranty Deed

5/2/1983

12/31/2035

2M4-CTS009

Contract for Deed

12/19/1983

12/31/2035

2M4-CTS010

Contract for Deed

5/23/1984

12/31/2035

2M4-CTS011

Warranty Deed

10/30/1984

12/31/2035

2M4-CTS013

Warranty Deed

11/19/1984

12/31/2035

2M4-CTS014

Contract for Deed

2/13/1985

12/31/2035

2M4-CTS016

Warranty Deed

12/30/1987

12/31/2035

2M4-CTS017

Warranty Deed

3/30/1988

12/31/2035

2M4-CTS019

Contract for Deed

6/10/1988

12/31/2035

2M4-CTS023

Warranty Deed

8/17/1989

12/31/2035

2M4-CTS025

Warranty Deed

11/5/1990

12/31/2035

2M4-CTS026

Warranty Deed

5/23/1991

12/31/2099

2M4-CTS027

Warranty Deed

5/23/1991

12/31/2035

2M4-CTS028

Warranty Deed

11/22/1991

12/31/2099

2PC-CTC018

Mineral Deed

2/28/2001

12/31/2099

2R-CTC015

Warranty Deed

7/17/1998

12/31/2035

2R-CTC016

Mineral Deed

11/2/1998

12/31/2035

2R-CTC017

Warranty Deed

12/28/1999

12/31/2999

2R-CTS044

Warranty Deed

10/24/1994

12/31/2035

2R-CTS049

Warranty Deed

6/28/1996

12/31/2035

2R-CTS050

Warranty Deed

8/1/1996

12/31/2099

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

2R-CTS054

Warranty Deed

4/16/1997

12/31/2035

2R-CTS055

Warranty Deed

4/18/1997

12/31/2035

2R-CTS062

Warranty Deed

8/26/1997

12/31/2035

2R-CTS068

Warranty Deed

5/5/1998

12/31/2035

2R-CTS069

Warranty Deed

7/29/1999

12/31/2035

2R-CTS070

Warranty Deed

12/30/1999

12/31/2099

2R-CTS074

Warranty Deed

1/15/1999

12/31/2035

2R-CTS076

Warranty Deed

12/28/1999

12/31/2999

2R-CTS078

Warranty Deed

1/17/2003

12/31/2035

2R-CTS082

Warranty Deed

7/26/2001

12/31/2099

2R-CTS083

Quit Claim Deed

9/13/2001

12/31/2099

2R-CTS089

Warranty Deed

8/21/2002

12/31/2035

2R-CTS106

Warranty Deed

9/10/2004

12/31/2035

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

3.4 SIGNIFICANT ENCUMBRANCES TO THE PROPERTY

The Freedom Mine currently has no significant encumbrances to the property. No Notice of Violations (NOVs) have been issued at the Freedom Mine in over ten years. Permitting requirements are discussed in Section 17.0.

3.5 SIGNIFICANT FACTORS AND RISKS

Coteau has not identified any significant risks that may affect the right or ability to perform work on the property. Each lease and special obligations for each lease are reviewed on an annual basis to ensure there is no lapse in lease continuation or payments. If a lease expires or a payment lapses, the landowner may choose not to release this property for mining.

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

3.6 REGISTRANT ROYALTIES AND INTERESTS

Discussed in Section 3.3.

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

4.0 ACCESSIBILITY, CLIMATE, LOCAL RESOURCES, INFRASTRUCTURE, AND PHYSIOGRAPHY

4.1 PHYSIOGRAPHY, TOPOGRAPHY AND VEGETATION

The Freedom Mine, located in Mercer County, North Dakota (ND), is part of the glaciated subsection of the Missouri Plateau, which is part of the Great Plains Physiographic Province.

The region is currently characterized by glacially modified bedrock and glacial trenches. The mantle of drift generally follows the preexisting topography, modifying it only slightly, although in some areas there is some glacial constructional relief. The general effect of the drift has been to lessen the local relief. The major drainages and their main tributaries are pre-glacial bedrock valleys. The Knife River and Square Butte Creek are adjusting their profiles to the Missouri River base level, so they are currently aggrading streams. Relief in the area is due largely to erosion in contrast to the depositional landscape of the Missouri Coteau. Relatively softer siltstone and claystone layers locally have been dissected to produce badland topography, but more commonly, smooth rounded slopes are formed between benches. The maximum relief of the Freedom Mine is approximately 437 feet (msl), with the elevation ranging from 1,848 feet (msl) in the Zap Branch of the Beulah Trench to nearly 2,285 feet (msl) in the Tertiary upland ridge tops.

Predominant land use within Mercer County is agricultural in the form of cropland or native grassland. Additional land uses include tame pasture, wetlands, shelterbelts, roads, occupied farmsteads, and stock ponds.

4.2 ACCESSIBILITY

The main entrance to the Freedom Mine is accessed by traveling north of Beulah on Highway 49 for one mile, then north on County Road 21 for two miles, then west on County Road 26 for three miles, and then north on County Road 15 for two miles as shown on Figure 3.1. Location of the Freedom Mine.

Travel to the Freedom Mine by air is possible by means of the Bismarck Municipal Airport, Bismarck, ND, which is approximately 90 miles southeast of the mine. From the airport, the mine is accessed by means of ground transportation by traveling west approximately 50 miles via Interstate 94, taking exit 110 and traveling north approximately 28 miles on ND Highway 49 to Beulah, ND, and so on as explained in the previous paragraph.

Travel to the Freedom Mine by rail is possible using the Amtrak Network, which runs through northern North Dakota mostly along the US Highway 2 corridor, and passes through the larger cities of Williston, Minot, Grand Forks, and Fargo, and smaller cities of Stanley, Rugby, and Devils Lake. From these locations, the mine can be accesses via ground transportation on Interstate 29 or Interstate 94 and various highways. The main highways are US Highway 2, US Highway 83, US Highway 85, US Highway 200, and US Highway 281.

North Dakota’s freight rail service is largely provided by Burlington Northern Santa Fe Railway and Canadian Pacific Railway.

4.3 CLIMATE

The climate of the proposed permit area is semi-arid. It is a region of climatic extremes. Averages are misleading, for seldom does "average" weather actually occur. Instead, weather tends to fluctuate widely around the annual averages. The area is usually warm in summer, and has frequent spells of hot weather and occasional cool days. It is very cold in winter, when arctic air frequently surges over the area. Most precipitation falls during the warm period, and precipitation is normally heaviest late in spring and early in summer. Snowfall is normally not heavy.

Of the long-term average annual precipitation of approximately 16.8 inches, approximately 13.5 inches, or 80%, falls from April through September. In two years out of 10, the rainfall in April through September is less than 11 inches. Thunderstorms occur on about 34 days each year, and 26 of these days are in summer. Hail accompanies summer thunderstorms in small scattered areas. Blizzards occur several times each winter. Average seasonal

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

snowfall is 28 inches. On the average, 51 days have at least one inch of snow on the ground, but the number of such days varies greatly from year to year.

In winter, the average temperature is 12 degrees, and the average daily minimum temperature is one degree. In summer the average temperature is 67 degrees, and the average daily maximum temperature is 82 degrees. The percentage of possible sunshine is 70 in summer and 53 in winter. The average relative humidity in mid-afternoon is about 55 percent. Humidity is higher at night, and the average at dawn is about 80 percent. The prevailing wind is from the west-northwest. Average wind speed is highest in April.

4.4 LOCAL RESOURCES AND INFRASTRUCTURE

The towns of Beulah, Hazen, and Stanton along with other smaller communities are within a 40-mile radius of the Freedom Mine and provide a vast supply of the employment base. Employees also come from the cities of Bismarck, Minot, and Dickinson, all of which are less than 100 miles away from the mine.

The Freedom Mine sources power for mine office facilities and operations from Roughrider Electric Cooperative, a cooperative of BEPC, and water for the mine office facilities from the Southwest Water Authority. Fuel for equipment is supplied by multiple local vendors. The Freedom Mine has, or is currently constructing, all supporting infrastructure for mining operations. See Section 15.0 for further detail pertaining to the mine specific infrastructure.

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

5.0 HISTORY OF THE PROPERTY

5.1 PREVIOUS OPERATIONS

There were no previous operators of the Freedom Mine.

5.2 EXPLORATION AND DEVELOPMENT HISTORY

NACoal began exploring the area in the1970’s, more specifically in MA1, MA2, MA3, and MA4, known as the Beulah-Hazen Areas. The first surface mining permit for Coteau was approved in 1981, and initial boxcuts were opened in 1983. In later years due to the need to expand the mine’s capacity, the Renner’s Cove and Dakota Star areas were acquired. The Renner’s Cove area was originally explored by Consolidation Coal Company (CONSOL) beginning in the 1960’s. Coteau purchased the surface and coal leases for the Renner’s Cove Area from CONSOL in 1993. The Dakota Star area was also originally explored by CONSOL beginning in the 1970’s. Basin Cooperative Services (BCS) purchased the surface and coal leases in the Dakota Star Area from CONSOL. BCS continued the exploration of the Dakota Star area. Coteau purchased the Dakota Star Reserves from BCS in 1990.

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

6.0 GEOLOGICAL SETTING, MINERALIZATION AND DEPOSITION

6.1 GEOLOGY

REGIONAL GEOLOGY

The Freedom Mine is located within the glaciated subsection of the Missouri Plateau, part of the Great Plains Province. The formations of sedimentary origin were deposited in the Williston Basin, the dominant structural feature of western North Dakota. The center of this essentially symmetrical basin is located near the town of Williston, North Dakota, approximately 100 miles northwest of the mine site. The basin consists of approximately 15,000 feet of sedimentary rock overlying a basement complex of gneisses, schists, and granites. This sequence records a geologic time interval spanning late Precambrian (1 to 2 billion years ago) to Holocene (last 10,000 years).

The structural influence of the Williston Basin is reflected in the dip of the formations underlying the Freedom Mine area. Drill hole data indicates that the Sentinel Butte Formation, the uppermost bedrock unit of the sedimentary series within the Freedom Mine area (Figure 6.1), dips westward toward the center of the Williston Basin at 50 to 75 feet per mile (about ½ to 1 degree). The dip of the bedrock strata increases with depth due to the physical characteristics of the Williston Basin. The subsidence of the Williston Basin began early in the Paleozoic Era (425 to 542 million years ago). Subsidence has not been continuous, nor has sedimentation occurred at a constant rate. These irregularities are evidenced by the presence of several unconformities in the stratigraphic column of North Dakota.

From the Cambrian Period (488 to 542 million years ago) through the early Paleocene Epoch (55.8 to 65.5 million years ago), numerous shallow, inland seas advanced and retreated across the area now known as west-central North Dakota, depositing a wide range of marine and lagoonal sediments, mainly shales, limestones, and evaporites. Since the early Paleocene Epoch, only stream and lake sediments have been deposited in western North Dakota. Deposition of these sediments was interrupted during the late Tertiary Period (13 to 36 million years ago) by episodes of regional uplift, faulting, warping, and erosion.

During the Pleistocene Epoch (10,000 to 2.6 million years ago), continental glaciers advanced and retreated, modifying the existing topography by depositing varying thicknesses of glacial materials in the uplands area, and eroding and filling the diversion trenches. Following this period of aggradation, there was a gradual dissection of the present topography, which consists of rolling prairie, isolated buttes, mesas and badlands. Southwest of the Missouri River, glacial deposits are thin or absent, and the boundary of the Glaciated Missouri Plateau is poorly defined with the maximum extent of glaciation marked by glacial erratics.

The regional structural geology is fairly consistent. No evidence of any significant faulting has been observed in the region. The lignite seams are gently undulating due to differential compaction of the underlying sediments.

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

Figure 6.1. Geologic and Topographic Bedrock Map of North Dakota (Bluemle, 1983)

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

6.2 LOCAL GEOLOGY

The most prolific lignite-bearing stratum in the state is the Sentinel Butte Formation of the Fort Union Group. The most prominent characteristics of the Fort Union Group formations are the cyclical deposition and lateral persistence of the lithologic units, especially the lignite seams. The Sentinel Butte Formation is a continental deposit comprising interbedded calcareous clays, sandy clays, and lignite beds, with isolated lenses of fine-grained sands, silts, and rare limestones, ranging in color from light gray to dark brown and black. Except for the limestones and an upper sandstone unit, the sediments are essentially nonindurated. The claystone and sandstones are generally thinly bedded and not jointed. These sediments were deposited mainly in swamps or in the floodplains of very slow, meandering rivers. The Sentinel Butte Formation conformably overlies the Tongue River Formation (also known as Bullion Creek Formation). The Golden Valley Formation, which is stratigraphically above the Sentinel Butte Formation elsewhere, is absent in the Freedom Mine area, due to postdepositional erosion; therefore, the younger glacial deposits of the Coleharbor Group unconformably overlie the Sentinel Butte Formation in the study area. Outcrops of the Sentinel Butte Formation are sporadic; bedrock is largely masked by residual soils, slopewash, and/or glacial drift.

Where the entire Sentinel Butte Formation is present, as in western Mercer County, its thickness is approximately 500 feet. The upper part of the formation in eastern Mercer County, however, has been removed by erosion, thus it is only about 350 feet thick. The thickening of this formation westward is due also to the increasing thickness of the upper sandstone unit to the west. This upper member is a fine to medium grained, yellowish-brown sandstone. Generally, it is poorly cemented, but locally it is moderately to well cemented. The cemented sandstone is dark brown and forms conspicuous ledges 5 to 10 feet in height, but these are laterally discontinuous.

The Sentinel Butte Formation incorporates a varying number of lignite coal beds (Figure 6.2 Stratigraphic Column of the Freedom Mine). The major lignite bed within the mine area is the Beulah-Zap (Beulah) bed, the only economical lignite deposit. This lignite horizon has a thickness of generally 15 to 22 feet, except near the edges of the glacial diversion channels, where some of the lignite bed has been removed by erosion. Also, along the glacial diversion channels are areas of soft lignite (leonardite). Soft lignite is a result of areas of the bed being exposed to oxidizing conditions via erosion caused by glacial meltwaters. The soft or weathered lignite is of very poor quality and not economically recoverable.

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

Figure 6.2 Stratigraphic Column of the Freedom Mine

SEC S-K 1300 Technical Report Summary

The Coteau Properties Company – Freedom Mine February 14, 2022

At the Freedom Mine, the Beulah bed can split into four components, an upper split (Upper Beulah), and a lower split (Lower Beulah). In some locations, the Upper Beulah splits into the Upper Beulah 1 and Upper Beulah 2. Also, in some locations, the Lower Beulah splits into the Lower Beulah 3 and Lower Beulah 4. The splits hold a combined thickness of approximately 15 to 20 feet and then they start to thin to a combined thickness of approximately 10 to 11 feet.

Located above the Beulah bed are several thin beds of lignite (Figure 6.2). These include, in the order that they occur, the Twin Buttes and Schoolhouse beds. These beds typically average 2 feet thick, although they range from 1 foot to 6 feet within short distances. Interburden between the Schoolhouse and Beulah beds ranges from 5 to 50 feet, and interburden between the Twin Buttes and Schoolhouse beds averages 65 feet.

Located below the Beulah bed are several other beds of lignite (Figure 6.2). The major beds, in the order below the Beulah bed that they occur, are the Spaer and Stanton beds. These range from 65 to 130 feet below the Beulah bed. The Spaer bed has an average thickness of 5 feet, and lies an average of 80 feet below the Beulah bed. The Stanton bed averages 5 feet thick, and lies an average of 35 feet below the Spaer bed. Other thin beds and splits of the two beds, typically less than 2 feet thick, are occasionally found above and below the Spaer and Stanton beds. Below the Stanton bed can be found the Hagel lignite zone, generally made up of two to three beds, and then below that the Tavis Creek bed. Below the Tavis Creek bed is generally a long sequence of sands and clays before the next lignite (150-300 feet). The Jim Creek bed is a localized lignite bed that appears between the Beulah and Spaer beds.

Geologic cross section B-B’ from the NACT-0401 permit area is included for reference as Figure 6.3 in the Supplemental Figures Attachment. The cross-section was constructed primarily based on the drill hole geophysical logs supplemented with lithology descriptions from the drill cuttings, as well as the data from the core holes.

Workings of inactive or abandoned surface and underground mines have been identified prior to mining. Since mining began, no unique or especially significant geological features, formations, or paleontological resources have been identified at the Freedom Mine. Additionally, no fatal flaws related to geological conditions have been identified.

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7.0 EXPLORATION

7.1 EXPLORATION

No exploration work other than drilling and associated geophysical logging has been conducted at the Freedom Mine. Geophysical logging is discussed with drilling in Section 7.2.

7.2 DRILLING EXPLORATION

Data collected during drilling exploration programs at the Freedom Mine is the sole information available for modeling the lignite deposit for the determination of Mineral Resources and Reserves. The sampling method used by the Freedom Mine for modeling quality of the lignite deposit is exclusively core drilling. The Freedom Mine lignite deposit is evaluated on a seam by seam basis. Drilling exploration data including geologic lithologies, qualities, and hole locations have been compiled electronically in Excel files.

DRILLING TYPE AND EXTENT

Drilling exploration programs conducted at the Freedom Mine have comprised largely of rotary air/mist/mud drilling methods. For the purpose of this discussion, senior geologist and field geologist refer to qualified representatives of Coteau and/or NACoal. Historically, Coteau has contracted independent drilling services and geophysical logging services. Drill holes completed at the Freedom Mine are vertical in orientation and have been broken into four categories which are described below. A drill hole location map for the Freedom Mine is presented in Figure 7.1 in the Supplemental Figures Attachment.

Exploratory drill holes, also referred to as pilot holes, are typically 5-inches outer hole diameter (od) and terminate at a minimum of 12-feet below the lowest targeted lignite seam as specified by the senior geologist to allow for proper geophysical logging. Drill hole cuttings are recovered by the contracted driller on a 5-foot interval and are described by the field or senior geologist. All pilot holes are geophyscially logged by a third-party geophysical logging contractor for natural gamma, density, caliper, and resistivity responses. There are instances where a geophysical log cannot be obtained due to poor, collapsing hole conditions, however, footage information is obtained from the driller and the cuttings descriptions.

Coal core holes to collect samples for quality assessment are advanced next to pilot holes at specified locations in accordance to protocols described below. Core holes are typically 5.6-inches (outer diameter, od) to core point, then 4.6-inches (od) during coring, with a respective sample diameter of approximately 3-inches (od). Samples are collected with either a 10-foot or a 15-foot split inner tube core barrel. Coring intervals are determined by the field geologist and reviewed by the senior geologist based on the pilot hole’s geophysical log and cuttings descriptions. 90-percent coal core recovery is required (see Section 8.0 for discussion on sample preparation).

Overburden core holes are drilled in accordance to protocol similar to the pilot holes and coal cores as described above. During the drilling of the core hole, overburden, interburden, and underburden samples are collected from the drill cuttings in 5-foot increments, and are shipped to a separate soil lab for geochemical analysis. The targeted lignite seams are cored as normal. 90-percent recovery of coal core intervals is still required within core runs that contain lignite, such that parameters outlined for coal core collection are maintained. Data specific to the coal cores collected during these overburden sampling programs are included in the geological model.

The fourth, and final, category of drill holes are comprised of geotechnical holes and monitoring wells which have been geophysically logged and extend through multiple coal seams. These drill holes follow the parameters outlined for pilot holes and available data has been reviewed by the QP.

GENERAL DRILLING PROCEDURES

Details may vary with each exploration program, however general procedures for drilling at Freedom Mine include:

–Identification of land control; acquire drilling permissions for properties not owned or previously leased.

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–Obtain proper drilling permits for drilling outside of mine permitted areas; acquire Mercer County Temporary Use Permit, and North Dakota State Exploration Permit.

–Site preparation.

–Rotary air/mist/mud drilling by an independent drilling contractor; typically, cuttings are collected every 5-feet.

–Field geologist logs description of cuttings including depth, texture, general color.

–Independent contractor geophysically logs drill hole for natural gamma, density, caliper, and resistivity.

–Field geologist reviews geophysical log.

–Hole determined complete, and abandoned by independent contractor in accordance with regulatory requirements.

–Survey drill hole collar location.

To continue with a coal core hole:

–Coring intervals are determined by field or senior geologist from pilot hole geophysical log.

–Coal core drilling by an independent drilling contractor.

–Core extracted from barrel by independent drilling contractor and placed in logging tray.

–Field geologist measures the core length, identifies the roof and floor, and does a macroscopic description of the core such as fractures, mineralization, texture, etc. If recovery is less than 90-percent, independent drilling contractor may attempt to retrieve the remaining core from the current hole. If no success, the core run interval will be “re-cored” as an additional core hole.

–Field geologist logs the core including depths, fractures, texture, color, and characteristics of the lignite.

–Field geologist double bags and tags sample.

–Once all intervals are cored, independent contractor geophysically logs drill hole if necessary.

–Field geologist reviews geophysical log.

–Hole determined complete and abandoned by an independent contractor in accordance with state regulatory requirements.

–Survey drill hole collar location.

Additional drilling tasks include:

–Maintaining daily drilling report and record of collected samples.

–Proper storage of lignite core samples in secure location of the mine warehouse to prepare for shipment to laboratory.

DRILLING EXPLORATION PROGRAMS

Numerous drilling exploration programs have been conducted at and around the Freedom Mine. The Freedom Mine’s drill hole database contains 7,855 drill holes that are used to model the Freedom Mine's coal field (Figure 7.1 Location of Drill Holes). Out of the total number of drill holes in the database, 3,904 of those drill holes are cored holes that were sampled for coal quality assessment.

The data for 7,245 of the 7,855 drill holes were collected by NACoal/Coteau beginning in 1974, through present. For the majority of these drill holes, Mohl Drilling, Inc. was the main drilling contractor, Century GLS performed much of the geophysical logging, and Minnesota Valley Testing Laboratories, Inc. (MVTL) performed much of the quality analyses.

NACoal/Coteau obtained drilling information on 610 of the drill holes in the Coteau database from outside entities which includes CONSOL and BEC.

Coteau’s drill hole database includes data for 423 drill holes obtained from CONSOL. Out of the 423 drill holes, 114 drill holes are from exploration conducted by CONSOL from 1964 to 1980 for the Renner’s Cove Area. The drilling was performed by CONSOL, and Nuclear Logging Services performed the geophysical logging. Also

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included in Coteau’s database is drilling information for 309 drill holes from exploration conducted by CONSOL from 1973 to 1980 for the Dakota Star Area. There were various independent drilling and logging contractors that included CONSOL and Nuclear Logging Services. The method used to survey the drill holes obtained from CONSOL is unknown.

Coteau’s database also includes drilling information for 187 drill holes from exploration conducted by BEC from 1989 to 1992 for the Dakota Star Area. There were various independent drilling and logging contractors that included Mohl Drilling and Century GLS.

The majority of the drill holes collected by CONSOL and BEC were geophysically logged, and field logs were maintained to describe the geology. The majority of the coal cores collected during these drilling campaigns were analyzed by CONSOL’s lab or MVTL.

These data collected by CONSOL and BEC were the basis for the characterization of the lignite deposit to justify the expansion to the Renner’s Cove and Dakota Star Areas. Despite uncertainty in how these early drill holes were surveyed, and how the data was collected, the data collected by CONSOL and BEC has remained fairly consistent when compared to fill-in drilling and quality analyzed before and during active mining operations. The reliability of the drilling data obtained from CONSOL was proven in the Renner’s Cove Area, due to the consistency with fill-in drilling and the area being successfully mined out by Coteau. The data in the Dakota Star Area has proven to be reliable due to the consistency with fill-in drilling and successful mining in the area. The QP has evaluated the reliability of the drilling data provided by CONSOL and BEC to NACoal. Drill holes deemed reliable have been used to model the lignite structure, and core holes in which the quality data could be verified by laboratory reports were used to model lignite quality. Original drilling files acquired from CONSOL and BEC are securely stored at Coteau. A summary of records is provided in Table 7.1.


						Available Data
Company	Year	Drilling Contractor	Geophysical Logging Contractor	Pilot Holes	Coal Core Holes	Holes with Geophysical Log	Holes with Core Log	Holes with Lab Analysis
Consolidation Coal Company (Renner's Cove)	1964-1980	Consolidation Coal Company	Nuclear Logging Service	87	27	96	27	27
Consolidation Coal Company (Dakota Star)	1973-1980	Various Contractors1	Various Contractors2	215	94	291	94	94
Basin Cooperative Services (Dakota Star)	1989-1992	Various Contractors3	Various Contractors4	133	54	178	54	54
1 Contracted by Consolidation Coal Company; included Consolidation Coal Company
2 Contracted by Consolidation Coal Company; included Nuclear Logging Service
3 Contracted by Basin Cooperative Services; included Mohl Drilling, Inc.
4 Contracted by Basin Cooperative Services; included Century GLS

Table 7.1. CONSOL and BCS Early Drilling Exploration Summary

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QUALIFIED PERSON’S OPINION ON DRILLING EXPLORATION

The QP has been involved in drilling exploration programs since 2009, and has served as the senior geologist who has overseen the drilling exploration programs conducted from 2012 through present at the Freedom Mine.

As a whole, Coteau plans exploration activities to attain an average 660-foot drilling density for the three-year projection ahead of active mining operations. Thus, the drilling patterns are drilled such that the hole spacing is progressively tightened as mining progresses. In initial exploration areas, drillhole spacing may be as much as one mile apart. Where mining is planned to be more than 10 years away, the hole spacing might be as much as one quarter mile. Within three years of mining, the drilling pattern is complete, and the interior spacing is approximately one hole per 20 acres (660-foot grid). The geology of the erosion and weathering of the coal is complex at the Freedom Mine, therefore dense cropline drilling takes place. Final subcrop definition is rows of holes 100 feet apart every 300 feet along the subcrop line. Physical constraints such as stream buffers, occupied dwellings, and rough terrain can affect the final drilling density. This spacing allows operations to optimize seam blending efforts to ship a steady fuel quality to the customer. It should be noted for the purpose of Mineral Resource estimations and Life of Mine (LOM) projections, the QP has determined a moderate to high level of confidence in a minimum drill hole spacing of 1,320-feet. This confidence comes from the continuity of the lignite seams including both lithologic and quality characteristics, as well as the ability to compare modeled seam projections to active and historical mining operations. The Freedom Mine has been a producing mine for over 38 years, and has successfully mined over 522 million tons of lignite based on the geologic model built off the drilling data in Coteau’s database. Further justification of the drill hole spacing specific to Mineral Resource Classifications is discussed in Section 11.0.

Physical constraints such as stream buffers and unnavigable terrain may affect the consistency in drill hole spacing. Additionally, drilling exploration for later years does not always land within fully permitted areas which may limit the extent of disturbance allowed.

FACTORS THAT CAN AFFECT THE ACCURACY AND RELIABILITY OF THE DRILLING RESULTS

During the drilling and sampling procedure, a variety of factors could materially affect the accuracy and reliability of the results. Some examples include improper surveying of the drill hole collar location and elevation, improper and un-level drill rig set up, improper zeroing out of the geophysical logging tool before commencing geophysical logging, not being able to obtain a geophysical log due to collapsing drill hole conditions, not obtaining 90% recovery of the coal seam cored, allowing the coal core to be exposed for too long before bagging causing a false reduction in moisture and increase in BTU value, and improper record keeping. Most of these negative factors can be avoided by utilizing skilled and experienced drilling and geophysical logging contractors, having proper QA/QC procedures to follow during sampling, and proper drill hole data verification.

7.3 HYDROGEOLOGIC CHARACTERIZATION

SURFACE WATER

Initial background surface water studies were conducted in 1978 through 1980 for Antelope Creek and its tributaries by the Coteau Properties Company. This study was in addition to two other more comprehensive studies conducted for the Antelope Valley Station Environmental Assessment (1977) and American Natural Gas (ANG) Coal Gasification Company Environmental Impact Statement (1978). Analyses of 17 trace metals were conducted for the Antelope Valley study.

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The ANG Coal Gasification Company study includes an evaluation of the potential effects of drainage from the plant and mine site resulting in annual mean monthly runoff for several station at or near the mine site. Estimates of flood magnitudes are also included in this report.

The U.S. Geological Survey has monitored several sites along streams that drain areas currently permitted by Coteau. Previous data from currently inactive USGS stations, or ongoing data from currently active USGS stations, may be used for evaluating variability in water quality and quantity.

Monitoring at surface water sites is conducted a minimum of 2 years prior to mining, throughout the mining process until bond release of the area. The data is used to prove the lands and surface water have been restored to their pre-mining condition.

GROUNDWATER

The primary water bearing strata in the Freedom Mine permitted areas include shallow alluvial sands associated with the mantle of glacial till overlaying the permit areas, deeper fluvial sands, the upper lignite beds of the Sentinel Butte Formation, alluvium-filled glacial meltwater channels of the Coleharbor Formation that include the Beulah Trench and Renner Trench, and deep sandstone beds associated with the Upper Hell Creek and Fox Hills Formations. The Upper Hell Creek Formation and the Fox Hills Formation underlay all of Mercer County. The depth of the original glacial meltwater channels is such that it eroded through the upper portion of the Sentinel Butte Formation, causing the shallow lignite beds within this formation to subcrop along the valley walls of the trenches. The Antelope Creek Aquifer is contained in the glaciofluvial sediments of the Beulah Trench. North Dakota Geological Survey Bulletin 56 (Part III) – Ground Water Resources, Mercer and Oliver Counties, North Dakota reports that wells completed in the Antelope Creek aquifer should be capable of yielding 100 to 500 gallons per minute. It also reports that the aquifer contains about 260,000 acre-feet of ground water. This same report states that most wells completed in the lignite bed aquifers of the Sentinel Butte Formation yield less than 10 gallons per minute, which is sufficient for their intended use. The lignite beds serve as the primary supply of ground water for domestic and livestock purposes due to their areal extent.

A minimum of two years of baseline ground water data were collected and studied within each permit area at the Freedom Mine. The baseline data collection included water levels, water qualities (alkalinity, hardness, total dissolved solids (TDS), major cation/anions, and select metals), potentiometric head, flow direction, and hydraulic conductivity calculated from pumping tests or single well response (slug) tests. Also, as part of the permitting process, domestic wells and springs within and surrounding the permit areas are certified to determine the well or spring location, well construction details, source aquifer, water chemistry, and pumping or flow rate. Over 300 monitoring wells and other wells of various types were utilized to characterize the ground water hydrology in and around the Freedom Mine.

A wide range of hydraulic conductivity values was observed in the lignite beds. In some areas, the lignite beds exhibit very low hydraulic conductivity on the order of 0.1 feet per day or less. In some areas of more permeable lignite, the hydraulic conductivity values are greater than 100 feet per day. The wide range of hydraulic conductivity values is indicative of the very nature of the lignite beds in the Sentinel Butte Formation. Sedimentary processes formed the lignite beds. Over time, minor fractures developed along the plane of deposition. The extent and degree of these planar, or bedding, fractures are variable. When viewed along a highwall in an open pit at the Freedom Mine, the variable planar fractures are very evident. The nature of this fracturing in the strata affects the hydraulic conductivity.

The glacial sands of the Beulah Trench yield hydraulic conductivity values on the order of 10 to 1,000 feet per day. These values, determined from field slug tests, correlate well with published values of hydraulic conductivity.

Slug tests in other glacial and alluvial sediments yielded hydraulic conductivity values of 1.1 feet per day to 33.3 feet per day.

The lignites have TDS that generally ranges from 238 mg/l to 6,180 mg/l, averaging around 3,000 mg/l, and are mostly a sodium bicarbonate type of water. The ground water quality for the Antelope Creek Aquifer includes TDS

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that ranges from 78 mg/l to 1,330 mg/l, with an average of 745 mg/l. The water is either a calcium or sodium bicarbonate type water. The ground water quality in the Renner Trench was variable. In the shallow till zones of the Renner Trench, the TDS ranged from 2,142 mg/l to 2,476 mg/l, with calcium and magnesium as the dominant cations, and sulfate as the dominant anion. Wells screened in the shallow sand zones of the Renner Trench yielded TDS values of 454 mg/l to 3,609 mg/l, with calcium and magnesium as the dominant cations, and sulfate as the dominant anion. In the deep sand zones of the Renner Trench, TDS values ranged from 1,450 to 2,164 mg/l, with sodium as the dominant cation and bicarbonate the dominant anion.

Locations of existing and destroyed ground water monitoring wells, along with certified domestic wells and springs are shown on Figure 7.2 Existing Monitoring Well Location Map, Figure 7.3 Destroyed Monitoring Well Location Map, and Figure 7.4 Certified Wells and Springs Location Map, found in the Supplemental Figures Attachment. These maps are excerpted from Coteau’s Consolidated Groundwater Monitoring Plan submitted October 2021. Many of the destroyed wells were once part of the monitoring program and part of the baseline aquifer testing, but were destroyed due to mining operations or due to being no longer needed.

No formal QA/QC document was available for the initial baseline data. However, use of duplicate samples and blanks were noted by the QP upon review of laboratory reports, chain of custody (COC) forms, and field notes related to the data collected.

Coteau’s Sampling Analysis Plan (SAP) thoroughly outlines the QA/QC protocols and procedures for field collection of groundwater and surface water samples in addition to the QA/QC methods implemented by the analytical laboratory. These QA/QC policies and procedures monitor the validity of the test results. Selected independent laboratories for water quality analyses follow the processes and meet the specifications published by national and international standard organizations including The NELAC Institute (TNI-NELAC) which administers the National Environmental Laboratory Accreditation Program (NELAP).

QUALIFED PERSON OPINION – HYDROGEOLOGIC CHARACTERIZATION

The hydrogeology of the Freedom Mine has been well studied. Coteau has continued to gain an understanding of the water bearing units during mining, established groundwater and surface water monitoring programs, fill-in drilling, and installation of new monitoring wells. The QP believes that these additional observations and collected data from the past 38 years of mining align with the results of the original surface water quantity measurements, aquifer tests, hydraulic conductivity tests, and water quality results.

7.4 GEOTECHNICAL STUDIES

EARLY GEOTECHNICAL STUDIES

Geotechnical soil drilling has been carried out at the property during several investigations. The most notable studies concerning baseline geotechnical properties are described below.

Initiated in 1977, and finalized in 1981, The North American Coal Corporation conducted a study to establish ground conditions and geotechnical properties for Mine Areas 2 and 4 at Coteau. The program was divided into five principle tasks: 1) research of available and pertinent literature and reconnaissance of nearby surface mines, 2) performance of test borings to secure samples of soil and rock, geophysical logging of the test borings, and installation of piezometers, 3) laboratory testing of undisturbed samples to yield data concerning cut highwalls, 4) laboratory testing of re-molded samples to yield data concerning spoil piles, and 5) analytical evaluation of all obtained data and formulation of pit design guides. A total of 19 borings were drilled and sampled, of which eight were drilled in MA2 and eleven were drilled in MA4. Seven borings were intermittently sampled, with a sample

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obtained within each five-foot increment of depth, and twelve borings were continuously sampled throughout their depths. All borings were drilled to levels below the lignite to be mined (Beulah bed). A total of 43 pneumatic piezometers were distributed in separate borings adjacent to ten of the sampled borings to determine the hydraulic pressures in the glacial till mantle, the rock above and below the lignite, and the lignite. Sample borings were advanced by combinations of hollow stem auger, rotary wash, and rotary core. Samples were obtained either intermittently by split-spoon, Shelby tube and Pitcher tube samplers, or continuously by Shelby tube samplers and PQ wireline core barrel. The split-spoon sampler obtained a 24” long cylinder with a 2” outer diameter. The Shelby tube samplers obtained a 30” long cylinder with a 3” outer diameter. The Pitcher tube sampler obtained samples similar to the Shelby tube but 36” long. The PQ wireline core barrel obtained 3.3” diameter cores. The borings were drilled by Test Drilling Service Company (TDSC) and geophysically logged by Century GLS. The samples were logged, described, sealed, and boxed by a geologist provided by TDSC. The samples were analyzed by the laboratory Goldberg, Zoino, Dunnicliff and Associates (GZD). Locations of the geotechnical borings are shown on Figure 7.5.

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Figure 7.5 Location of Geotechnical Borings

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In 1984, Bauer, Calder, & Workman Inc., conducted a slope stability study in the active MA4 south area to provide direct information for use by engineering and operations to ensure stability throughout the range of normal operating conditions. The geology of the open pits was examined along with fractures and any failures that had occurred. Spoil heights and spoil angles of repose were measured and spoil samples were taken. Several vane shear tests were taken in the spoiled waste with a Geonor field testing unit. Some readings were located in freshly excavated material, while others were in waste that had been in place for two to three weeks. Vane penetrations were 8 to 23 inches. In most cases the vane was penetrated with its axis normal to the face of the slope. Skin friction readings were taken at all test locations and the vane dial readings were adjusted accordingly. Several hundred pounds of spoil samples were collected during the field tests, and cone tests were conducted on the samples. The cone test was developed by the contractor and were found to be very useful in determining bulk densities of spoiled materials, angle of repose, and swell factors. The test consists of pouring up to 200 pounds of material onto the laboratory floor forming a cone with dimensions governed by the material angle of repose. The sample was then tamped to simulate the action of draglines dumping. The cone height and diameter were measured and the sample was weighed. The desired parameters were then calculated. In addition, Bauer, Calder, & Workman utilized the results of the extensive soils testing done by North American Coal Corporation in the previously mentioned report in 1977-1981.

The typical geotechnical borehole log includes the following geotechnical descriptions and records of the sample collected during investigation:

–Lithology: Descriptions of the lithology (typically glacial till, sands, clays, silts, sandy silts, sandy clays, clayey silts, and clayey sands) are recorded for each stratigraphic interval in conjunction with a soil type in accordance with the Unified Soil Classification System (USCS). The soil types encountered by The North American Coal Corporation, 1977-1981 at the boring locations include clayey sands (SC), silty sands (SM), silty and sandy clays (CL), clays (CH), glacial till, and lignite.

–Sample Type and Laboratory Data: For the 1977-1981 NACoal report, GZD laboratory re-logged each sample in detail and performed in-place strength and behavior testing of each principle material encountered. The testing included grain size distribution analyses, specific gravity analyses, direct shear tests, triaxial shear tests, and unconfined compression tests. Subsequent to the testing of undisturbed samples, a testing program was formulated to determine the approximate character and strengths of mine spoil, or disturbed, mixed, and cast overburden. The same tests (except unconfined compression tests) were performed on the disturbed samples as were on the undisturbed, but with the addition of moisture-density (Proctors) and swell potential tests.

The typical laboratory tests performed in the investigations described above were carried out in accordance with the relevant American Society for Testing and Materials (ASTM) standards at independent certified laboratories. The laboratory testing methods completed to determine the geotechnical soil parameters are appropriate for the purpose of detailed geotechnical design.

These studies have been used to incorporate best practices and supporting data for the Freedom Mine Ground Control Plan that is submitted to the Mine Safety and Health Administration (MSHA). Guidance for operational parameters such as digging methods, height of prebench highwalls, height and angle of dragline highwalls, spoil height and the best road building materials have all been gleaned from the information provided in the aforementioned geotechnical studies.

Further detail concerning pit design and ground control parameters related to geotechnical studies are discussed in Section 13.0 Mining Methods.

QUALIFED PERSON OPINION – GEOTECHNICAL STUDIES

Subsurface conditions and geologic units encountered have remained fairly consistent since mining commenced in 1983. Overburden core holes in which individual sections of burden were collected and tested for physical and

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geochemical properties, as described previously under drilling exploration, have been evenly distributed throughout the permitted mine areas and continually serve as an indicator for soils to be encountered ahead of mining. Furthermore, the geologic structural data acquired from geophysical logs during drilling campaigns indicate consistent depths between burdens and lignite seams among other subsurface characteristics. Special situations have led to additional geotechnical studies specific to the issue encountered while mining. However, the general pit parameters defined by the above studies have not warranted a need for further studies from the continued information obtained from drilling exploration and active mining operations. The QP understands that additional geotechnical studies may be required on an as needed basis to address special conditions that may be encountered in future mining.

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8.0 SAMPLE PREPARATION, ANALYSES, AND SECURITY

8.1 SAMPLE COLLECTION AND SHIPMENT

The Freedom Mine lignite deposit is evaluated on a seam by seam basis. As a standard in the coal industry, individual horizons of lignite are bagged and sent to a third-party coal testing laboratory. The procedures at the Freedom Mine for current and historical sample collection are summarized below.

Core runs are specified by the senior and/or field geologist by referencing the geophysical log of the pilot hole. Once a specified core run is brought to the surface, the field geologist observes the drillers extract the lignite sample from the split tube core barrel to ensure the integrity of the sample is maintained, and to verify the top and the bottom of the core run. The core sample is transferred from the core barrel to a core trough (i.e. aluminum core trough with a built-in measuring scale). The field geologist verifies the roof and floor of the lignite core is present and checks the expected coal seam thickness referenced from the pilot hole’s geophysical log to determine coal core recovery. If 90-percent recovery cannot be verified, the driller may attempt to retrieve the remainder of the lignite core run from the current hole. If no successful attempt is made to recover the remaining lignite, the driller must re-core the core run in a new adjacent core hole.

Upon verifying full recovery of the core run, the field geologist succinctly, but thoroughly logs the lignite run. A typical log describes:

–“to” and “from” depths of burdens and lignite;

–joints and fractures at specified depths;

–characteristics of burden above and below the lignite core;

–roof and floor of lignite seam (i.e. sharp or gradational);

–presence of pyrite or petrified wood;

–observations of clay or sands imbedded in the lignite core;

–and any other prominent characteristics.

After the field geologist describes the core run, the entire lignite section is double bagged and tagged (on the inside bag). Tags include the date, mine identifier, hole ID, seam ID, and “to” and “from” intervals. Double bagging preserves the moisture of the sample, and tagging on the inside bag safeguards the identification of the sample from the field through transportation to the third-party laboratory. Also, the same information on the tag is also written on the outside of the plastic sample bag. Historically, the Freedom Mine has not photographed coal cores prior to bagging samples.

Lignite cores may be split into multiple samples for the following reasons:

–Prominent roof, floors, or partings within a continuous seam;

–Identification of composition concentrations (i.e. to determine if sulfur trends toward top, middle or bottom of seam)’

–Separation of mineralized zones, such as limestone.

Total core runs are shipped for analysis, thus split samples in the context of a retained sample are stored at the third-party laboratory until the senior geologist determines they can be disposed of. Lignite tends to be a high moisture coal which oxidizes rapidly and does not have a long shelf life once removed from the ground. If core splits were retained, they would not be representative of in-situ coal properties over time.

After samples are bagged, they are stored in a dry, shaded area, typically the field geologist’s truck, until the geologist returns to the mine office. Core samples are then securely stored at the mine warehouse to be shipped to the third-party laboratory. The Freedom Mine office and warehouse is secured with user specified fob access and camera surveillance.

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Prior to shipping the samples, the senior geologist reviews each sample against the field records and the chain-of-custody (COC). The date, mine identifier, hole ID, seam ID, and “to” and “from” intervals are verified. A copy of the COC is emailed to the laboratory manager. Copies of the COC forms for coal cores shipped from 2012 through 2021 were available for the QP to review. Coal core samples are shipped to the third-party laboratory via insured freight with tracking information.

8.2 SAMPLE PREPARATION AND ANALYSIS

Minimum analyses of coal cores include short proximate (moisture, ash, BTU/lb, sulfur), sodium, calcium, and forms of sulfur. These parameters are the primary quality inputs used to model the Freedom Mine lignite deposit. Additional analyses of coal cores may include full proximate, ultimate, mineral analysis of ash, trace elements, and ash fusion, however, these parameters are not modeled or currently relevant for consideration of Mineral Resource estimations.

Minnesota Valley Testing Laboratories, Inc. (MVTL) in Bismarck, North Dakota is the main third-party laboratory the Freedom Mine uses for coal core analyses. MVTL has provided coal quality analysis in accordance ASTM standards for over 40 years. The ASTM standards that MVTL follows for coal analysis are listed below in Table 8.1.


Specific Tests and/or Properties Measured	Specification, Standard, Method, or Test Technique	Items, Materials or Product Tested	Key Equipment or Technology
Ash in the Analysis Sample	ASTM D7582	Coal	TGA
Calorific Value	ASTM D5865	Coal	Calorimeter
Carbon, Hydrogen, and Nitrogen	ASTM D5373	Coal	Elemental Analyzer
Chlorine	ASTM D6721	Coal	Micro-coulometric Analyzer
Fusibility of Ash	ASTM D1857	Coal	Furnace
Mercury	ASTM D6722	Coal	Direct Combustion Analysis
Mineral Analysis of Ash	ASTM D3682/D5016	Coal	ICP-OES, FIA, Furnace
Oven Dry Moisture	ASTM D7582	Coal	TGA
Air Dry Moisture	ASTM D3302	Coal	Air Dry Ovens
Preparing Samples for Analysis	ASTM D2013	Coal	Crusher / Pulverizer
Sulfur (Total)	ASTM D4239	Coal	Furnace
Sulfur Forms	ASTM D2492	Coal	Gravimetric, AA
Trace Metals	ASTM D6357 Modified	Coal	Microwave Digestion, ICP-MS & ICP-OES
Volatile Matter	ASTM D7582	Coal	TGA

Table 8.1. List of ASTM standards for MVTL.

Sample Receiving and Sample Storage Room

The sample receiving and storage room is climate controlled (ventilated, AC, and heat). Samples are received through various couriers, directly from clients, or from the MVTL Field Service division. The samples are cross referenced with a chain of custody form or other client paperwork and then are logged into the Laboratory Information Management System (LIMS). Each sample is given a unique lab number used for tracking during analysis and throughout the reporting process.

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Samples are stored until they are ready to be crushed in the prep room. There is a slight potential for moisture loss during this storage period. Coteau acknowledges this potential and, as such, double bags samples in the field to preserve as much in-situ moisture as possible.

Retained pulverized and air-dried 60-mesh samples are also stored in this room. These samples can be reanalyzed within 6 months for selective parameters. MVTL contacts and verifies with the client prior to disposal of retains.

Prep Room

The prep room is a temperature-controlled room (AC and Heat) accessible from the sample receiving and storage room. Within the prep room, samples are crushed to 8-mesh and are reduced in volume using a riffler. Two different sized crushers and rifflers are available depending on sample size. Compressed air is used to clean the crusher and riffler after each sample to mitigate contamination.

A riffled split of 8-mesh coal is placed on a sample tray and weighed. The weights are sent electronically to LIMS for use in the moisture calculation. The tray is placed in an air dry oven and dried overnight. The temperature of the air dry oven is monitored and recorded daily. The temperature monitoring devices are verified annually. Another riffled split is sealed in a Ziploc bag and retained. The client is notified prior to disposal of the coal core splits.

Laboratory Testing

All of the analyses in the laboratory are performed on the 60-mesh sample or ash prepared from it. The samples are mixed by tumbling prior to each analysis. The lab is climate controlled (AC and heat). Coal analysis results are reviewed prior to reporting. The review includes identification of outliers and comparison of results with historical information by site, if available. The analyses are re-analyzed as needed.

8.3 QUALITY CONTROL PROCEDURES

MVTL participates in round-robin testing programs specific to lignite with other laboratories to ensure result accuracy. MVTL participates in an Interlab Coal Round Robin Program monthly. In 2020, MVTL also participated in a lignite (coal) specific round robin program with NACoal including 8 commercial laboratories, one of which was MVTL, that were used by various NACoal mine locations. The round robin consisted of four samples labeled 2001, 2002, 2003, and 2004. The four samples were sourced from two NACoal mines. The two locations provided a range of samples with variability in moisture, ash, sulfur and sodium. The labs participating in the round robin were provided 8-mesh splits and dried, 60-mesh splits of all 4 samples. The general results are summarized in Figure 8.1. MVTL is labeled “Laboratory #5”.

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Figure 8.1. NACoal 2020 Round Robin Program Summary. (NACoal, 2020)

The QP feels the methodologies used at MVTL are within industry standards for sample preparation, process of sample splitting and reduction, general quality control, and security of samples to ensure that validity and integrity of samples is upheld.

8.4 QUALIFIED PERSON’S STATEMENT ON THE ADEQUACY OF SAMPLE PREPARATION, SECURITY AND ANALYTICAL PROCEEDURES

The consistency in core collection from one drilling program to the next at the Freedom Mine has been thoroughly documented. Through records review and personal observation of numerous drilling campaigns, it is the QP’s opinion that historic coal core collection has remained consistent. The process of double bagging and tagging the cores in addition to multiple checkpoints to log samples from field to shipment to the laboratory further ensures the integrity and security of each sample is maintained.

Additionally, in the QP’s opinion, the methodologies used by MVTL are within ASTM standards for sample preparation, process of sample splitting and reduction, general quality control, and security of samples to ensure that validity and integrity of samples is upheld.

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9.0 DATA VERIFICATION

9.1 DATA VERIFICATION OF DRILL HOLE DATA AND GEOLOGIC (MINERAL RESOURCE) MODEL AND MINERAL RESERVES

The drilling database for the Freedom Mine was organized into three Excel files related to lithology intervals, collar survey, and quality. The files encompass the geologic modeling inputs including lithology intervals, collar survey, total depth of hole, hole coordinates, and coal core quality data.

The drilling files were saved on the Coteau network drive which contains the geologic model and has limited access.

Once the drilling database was compiled, a series of routine data integrity checks were performed by the QP on the database to check for common errors and omissions. The QP visually inspected the database after updates were made, then conducted a second data validation check using Carlson Software. The validation checks included, but were not limited to, the following:

- Verified each hole has a unique collar location.

- Verified the total hole depth on the collar table matches the total depth on the lithology table.

- Verified the from and to depths on the lithology table and quality table increase down hole.

- Verified for overlapping intervals in the lithology table based on from and to depths.

- Verified the from and to depths on the quality table match the associated seam depths on the lithology table.

For any errors or omissions reported, the QP reviewed the geophysical logs, field logs, and quality reports related to the specified holes to reconcile the differences.

After the initial checks and reconciliations were completed, the QP completed the modeling process which is detailed in Section 11.0. Drill hole locations were randomly selected to verify modeled values of each horizon were representative of the imported drill hole data. Additional visual inspection of the model included review of various consecutive cross sections as well as isopach maps of the modeled structure (roofs, floors, and seam thickness) and quality. Newly modeled grids were also compared to previous models. Changes in modeled values were minor and isolated to areas where new drilling data had been included from recent exploration programs. Anomalies, such as spikes in the data were reviewed against the original drill hole data, any errors in the drilling database were reconciled and the model was reconstructed.

It is the QP’s opinion that the analytical results from the coal cores collected during Coteau’s exploration programs are consistent with actual as-delivered quality from the active mining operations at the Freedom Mine. This opinion was based on comparison of historical quality projected from the Carlson model for the annual operating plans to actual as-delivered quality indicated by the customer’s DGC Chemistry Lab. It is also the QP’s opinion that the modeled structure of the lignite seams is consistent with active mining operations based on comparisons of modeled seam thickness and trends against actual surveyed seam thicknesses and trends.

The QP found the geologic model was a reasonable and reliable representation of the geologic structure and quality of the lignite seams (horizons) at the Freedom Mine.

The QP compared the Mineral Resource model supporting the Mineral Reserve for projected quality, volumes and lignite tons, and evaluated monthly and annual reconciliations and found the Mineral Resource model to be an accurate representation of the actual findings during mining operations.

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The geotechnical studies discussed in Sections 7.0 and 13.0 have been reviewed and it is the opinion of the QP that the geotechnical data is adequate to support the pit angles used by the Freedom Mine.

The QP reviewed the dilution assumptions and found them to be reasonable and consistent with realized results from the active mining operation. Recovery rates are continually being compared to actual recoveries for verification.

The QP has reviewed annual historical values for all costs, pricing assumptions and economic analysis to be reasonable for future projections, which are refined and updated using the historical values, to continuously improve accuracy of the projections. These have been used to support parameters used during mine planning.

The Mineral Resource model and other data provided as modifying factors, including those of 3rd party firms, were confirmed as adequate for use in Mineral Reserve Estimation for this TRS.

9.2 LIMITATIONS ON DATA VERIFICATION

Representatives of Coteau or NACoal were not involved in the original drilling exploration programs conducted by CONSOL or BCS. Coteau obtained the collar surveys, geophysical logs, coal core analyses, and geologist field logs related to each hole from CONSOL and BCS, but was unable to observe the drilling, sampling, or sample preparation for these data. The largest uncertainty lies in the method of the collar survey of the early data drilled from 1964 to 1980. It is unknown to what degree these holes were surveyed.

Coteau, overall, has contracted Mohl Drilling, Inc. and Century GLS, contractors used by CONSOL and BCS for the early exploration, to perform in-fill drilling programs, such that Coteau has gained familiarity in these contractors’ drilling and downhole mapping methods. Furthermore, comparisons of new drilling data to the older CONSOL and BCS data have been completed as fill-in drilling progresses ahead of mining. These comparisons, and the level of documentation CONSOL and BCS provided upon acquisition of the coal assets translates to a level of confidence in these data to use in the geologic modeling for Mineral Resource estimation. Nonetheless, there is still some uncertainty which the QP has considered in the determination Mineral Resource estimations as discussed in Section 11.0 of this TRS.

Throughout the 40+ year history of the Freedom Mine’s coalfield, NACoal has always used policies, protocols and procedures to ensure the accuracy and integrity of the drilling and coring data. Experienced geologists have always been on the drill rigs or supervising the field geologists on the drill rigs. However, technologies and understandings change. During some of the early exploration conducted by NACoal at the Freedom Mine, a survey grid was not established. Hence, drill hole locations and elevations were read from USGS topographic quadrangle maps. Verification of lignite quality and trends with newer drilling data has increased the confidence in the early data, but does not eliminate the inherent risk from lack of QA/QC parameters in this small percentage of data in the areas that have not been mined. Also, the small percentage of pilot holes that do not have a geophysical log due to poor/collapsing drill hole conditions, also introduces some uncertainty and decreases the accuracy in elevations, even though footages were provided by the drilling contractor, and logs of the drill cuttings were utilized.

It is the opinion of the QP that there are no limitations to data verification for Mineral Reserves.

9.3 QUALIFIED PERSON’S STATEMENT OF ADEQUACY OF DATA

Data disclosed in this TRS used for the preparation of geologic models for the purpose of Mineral Resource estimations at the Freedom Mine have been verified by the QP. The QP has been involved with the collection of these data during drilling exploration programs since 2009, and served as the senior geologist for drilling campaigns since 2012. These data include drill hole surveys, geophysical logs, coal core quality, and other relevant test data. Procedures discussed previously in this section follow coal industry standards and were used by the QP to reconcile any discrepancies upon review of the available data.

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The QP has verified the data disclosed, including prior technical studies used in the development of the modifying factors, cut-off grade, geotechnical studies, ultimate pit configuration, mine design, schedule, workforce and staff requirements, equipment needs, environmental factors including ground water and surface water studies, cost assumptions and pricing assumptions and economic analysis. It is the QP’s opinion that the data provided for this TRS is sufficient for the determination of Mineral Reserves at the Freedom Mine.

It is the QP’s opinion that the data provided for this TRS is more than sufficient for the determination of Mineral Resources and Reserves at the Freedom Mine.

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10.0 MINERAL PROCESSING

Mineral processing does not occur at the Freedom Mine.

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11.0 MINERAL RESOURCE ESTIMATES

11.1 KEY ASSUMPTIONS, PARAMETERS, AND METHODS

The QP developed the stratigraphic geologic model for Mineral Resource estimation using Carlson Mining software. All verified drilling data through 2020 was included in the model. The Freedom Mine lignite deposit was modeled using U.S. customary units projected to NAD 1927 North Dakota State Plane, South Zone coordinate system. Key assumptions, parameters and methods to estimate Mineral Resources are discussed herein.

HORIZONS

The structure of the Freedom Mine deposit is determined by “to” and “from” depth intervals from geophysical logs and geologist’s field logs correlated to the drill hole collar survey. Depth picks represent the roof or floor of a lignite seam which define a horizon or domain.

Roofs, floors and partings that meet a mineable quality are identified as part of the associated seam, and are modeled in the same manner as the split samples described previously. Roofs, floors and partings that do not meet a mineable quality are included in the geologic database as a point of record, but are not modeled with a seam identifier, and thus the quality of those splits is not weighted with the associated seam.

Table 11.1 presents the Stratigraphic Horizons modeled for Mineral Resource estimation. Modeled horizons were required to have quality data in the drilling database to be considered.


HORIZON ID			SEAM NAME
UBE1			Upper Beulah 1
UBE2			Upper Beulah 2
UBEU			Upper Beulah
LBE3			Lower Beulah 3
LBE4			Lower Beulah 4
LBEU			Lower Beulah
BEUH			Beulah

Table 11.1. Stratigraphic Horizons

QUALITY PARAMETERS AND DENSITY DETERMINATION

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reported on an as-received (AR) basis. Five quality grids of the above parameters, along with forms of sulfur are modeled for each horizon. Generally, the only quality constraint on the mineability of the lignite at the Freedom Mine is weathering/oxidation, which causes a substantial decrease in the heat content of the coal. The lignite existence lines consider the weathering limits of the coal. The low BTU coal is removed from the mineable limits and is not considered as a mineral resource or reserve, therefore there are no quality constraints within the mineable limits of the coal field that can’t be mitigated by blending during mining to meet the customer needs.

NACoal was actively exploring and developing various coal fields in North Dakota, beginning in the early 1970s. The United States Geological Survey (USGS) and the United States Bureau of Mines had established the average specific gravity (density) of lignite to be 1,750 tons per acre-foot. This density was applied to all the reserve calculations being made by NACoal.

In 1957, NACoal purchased the Indian Head Mine in North Dakota. Annual comparisons of actual mined tons versus calculated tons showed that 1,750 tons per acre-foot produced good results, year after year.

During the late 1970s and early 1980s, coal production started at the Freedom Mine. A number of density studies were undertaken at the mine to confirm the validity of the density value being used. It was found that the ASTM specific gravity tests on coal cores and other coal samples produced results that were highly variable and difficult to composite into a single seam value. Variations in the organic composition and ash content were believed to be a major cause for the density variations. However, it was also found that when lignite dries, the coal’s structure collapses resulting in a higher density. This density increase from moisture loss is variable and cannot be prevented. For this reason, laboratory measured specific gravities on lignite were not used to calculated resources or reserves.

On several occasions at the Freedom Mine, density confirmation tests were conducted. For these tests, a relatively small area of a pit was defined and the coal was carefully loaded into trucks for weighing. Then detailed surveys determined the volume of coal removed. These volume and weight tests typically involved over 100 tons of coal and confirmed the 1,750 value; with some expected variability.

In addition, the mine was producing and delivering millions of tons of coal per year. Again, comparison of actual delivered tons versus predicted tons showed very good comparison.

During the mid-1980s, NACoal moved from manually drawn and measured maps of coal reserves to geologic computer models; with several different systems being used over the years. Each software package has its own requirements for entering density; some use grams per cubic centimeter while others use pounds per cubic foot and others tons per acre foot. The current geologic software being used by NACoal in North Dakota uses 80.0 pounds per cubic foot as the coal density. This value is slightly conservative (by less than 0.5%).

MODELING PROCESS

After the QP verified the drilling data in accordance with procedures outlined in Section 9.1, the stored drill hole data encompassing geologic lithology intervals, quality data, and collar surveys was imported into the modeling software.

Coteau builds three different models. The main model consists of all of the drilling data over the whole Freedom Mine coal field. This model is built with 200-foot grid cells. The main model is broken out into a West Mining Model and an East Mining Model. These models are built with 100-foot grid cells.

A surface topography grid is created from a compilation of pre-mining topography contours, which have variable contour intervals, but the densest contour interval available for the area was compiled. Some of the topographic lines are digitized from geologic quad maps, and others are contours from flight survey data. The surface grid is created by triangulation at a 200-foot grid cell size for the main model, and at 100-foot grid cell size for the West and East Mining Models.

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from a maximum of 20 surrounding drill holes using an inverse distance squared calculation to infill the grids where appropriate. The structural model was validated based on geological cross sections and isopach maps of the seam roofs and floors that were created and checked by the QP. Any errors identified in the lithologic descriptions were reconciled.

Lignite quality was then modeled for the entire deposit. As described above, quality data was first composited for each lignite seam by drill hole. As with the structural model, the quality model uses 100-foot or 200-foot grid cells to model quality of the deposit. Drill holes missing quality data employed an inverse distance squared calculation to assign averaged values from a maximum of 20 surrounding drill holes.

Generally, the only quality constraint on the mineability of the lignite at the Freedom Mine is weathering/oxidation, which causes a substantial decrease in the heat content of the coal. The lignite existence lines consider the weathering limits of the coal.

In-situ tonnages for the lignite seams were calculated within Carlson by applying a formula to each horizon by the area, thickness, density, and real/extrapolated quality values (i.e. modeled parameters).

JUSTIFICATION OF MODELING METHODS

Historically, geologic models at the Freedom Mine have been generated using inverse distance methods. These models were established and used in the development of detailed mine plans, financial projections, landowner tonnage estimates, daily operation plans, and month end reconciliations. The models have proved to be consistent with field conditions (structure and quality), which is likely attributed to the simplistic geology of the region as described in Section 6.0 of this TRS. Geologic units are laterally continuous with generally graded quality. Use of inverse distance methods has proven to be robust in continuous stratigraphic deposits. The QP did not see a need for Coteau to alter geologic modeling methods.

LIMITS AND CONSTRAINTS ON THE MINERAL RESOURCE ESTIMATES

The Mineral Resources presented in Table 11.4 were estimated by applying a series of geologic and physical limits in addition to mining and economic constraints which meet the level of detail required for an initial assessment (IA). Key constraints used by the QP to determine Mineral Resource estimates are summarized below. Details pertaining to physical constraints are discussed further within sections 3.0 and 17.0 of this TRS. Mining and economic constraints specific to Mineral Resource estimates are discussed herein.

Geologic Constraints:

–Modeled roof and floors of each lignite seam (horizon).

–Lignite Existence Lines-Croplines

Physical Constraints:

–Surface Topography.

–Lease and fee coal boundaries.

–Surveys of mined out areas

–Offsets from unleased land tracts and occupied dwellings.

–Existing roads and highways, major utilities, and major surface infrastructure without prior agreements for relocation or temporary closure.

Mining and Economic Constraints:

–Resource categorization parameters based on distance from point of observation and drill hole sample count criteria.

–Resource pit shells developed from general mine design parameters and reasonable unit costs used to determine the max cumulative strip ratio for the tonnage to be economical.

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GENERATION OF PIT SHELLS FOR MINERAL RESOURCE ESTIMATES

Resource pit shells were projected to meet the total tonnage requirements to provide lignite fuel to DCC through 2045 which is the current estimated lives of DGC and AVS. The field was analyzed, and the lowest cost portions of the model needed to match the required tonnage were included in the LOM plans. The existing lignite sales agreement between Coteau and DCC is in effect through 2037, therefore any tons within the LOM plan through 2037 are considered a reserve. Coal remaining outside of the existing contract end date is considered a resource.

All production included in the LOM plan will be delivered to DCC.

Under the LSA, Coteau receives a contractually-agreed fee based on the amount of lignite delivered. While Coteau is responsible for all mine operations, DCC is responsible for funding all mine operating costs and provides all of the capital required to build and operate the mine. This contract structure eliminates exposure to spot coal market price fluctuations.

Basic unit costs presented in Table 11.2 were used to determine the maximum reasonable effective stripping ratio of 13:1 for the Freedom Mine assuming an average lignite sales price of $1.70 mmBTU. The sales price has historically remained fairly steady due to the stripping ratio and delivered tons being fairly consistent. Unit costs were derived from general historic unit costs at the Freedom Mine.


Parameter	Unit	Cost
Burden Removal *	$/BCY	0.90
Royalty	$/ton	0.35

*Burden Removal unit cost was determined assuming the truck-shovel fleet, dozer fleet, and dragline each move 1/3 of the cumulative burden. Fleet unit costs are respectively assumed to be $1.20, $1.00, $0.50 per cubic yard.

Table 11.2. Unit Costs – Mineral Resource Estimation Parameters.

The geologic model was used to create a strip ratio map of the deposit. Recovery of in-situ tonnage was assumed to be 90-percent. No dilution factors were applied. Preliminary pit shells were determined by the QP based on the strip ratios, then modified for any physical constraints. General tonnage for areas were calculated in Carlson mining software with a simple closed polyline assuming vertical walls. Lignite quality grids were then individually loaded into Carlson mining software for the QP’s consideration with tonnage estimates to determine a general mine sequence and direction.

The QP projected 150-foot pits for each preliminary pit shell in the Carlson mining software. Lignite tonnages and burden volumes for each block were calculated in Carlson mining software then exported to Excel to generate volume and tonnage reports. To optimize the pit shell extents, cumulative strip ratios and cumulative mining costs for each exported block was calculated in MS Excel then visually modeled in a conditionally formatted table. Boundary adjustments were made to the preliminary pit shells accordingly and re-projected. Several mine plan iterations may be performed to optimize mining in the most cost-effective way.

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MINERAL RESOURCE CLASSIFICATION AND UNCERTAINTY

The Mineral Resource categorization applied by the QP includes the consideration of the abundance of data per drill hole and the spatial distribution of drill holes. Mineral Resources presented in this TRS were estimated and categorized as Measured, Indicated, or Inferred.

Table 11.1 identified the lignite seams for initial consideration of a Mineral Resource by the QP. The listed seams had a minimum of ten coal core samples for quality estimation. Mineral Resources were then further defined by the identified resource pit shells.

As discussed in Section 7.2, all drill holes within the Freedom Mine deposit obtained structural data related to the lignite seams, where a portion of these drill holes also included quality data from the collection of coal core samples. As such, the QP determined it appropriate that limits for spatial distribution between Mineral Resource categories were based on the average cartesian distances between drill holes that contained quality data. Defining the drill hole distances by the drill holes containing quality data ensured an appropriate density of the quality data was included in each Mineral Resource category. Additionally, due to the methodology of the fill-in drilling at the Freedom Mine, a greater density of quality data would naturally encompass a greater density of structural data.

Therefore, due to the uniformity of the structure and quality of the Freedom Mine coal field, drill hole distances that will define the spatial distribution between Mineral Resource Categories are based on the drill hole distances historically and currently utilized by Coteau As stated in Section 7.2, the minimum drill hole spacing within the controlled tracts within the permit boundary area at the Freedom Mine is 1,320 feet, and fill-in drilling tightens the spacing to approximately 660 feet. This drilling density has reliably predicted coal tonnage and quality for over 38 years.

The defined distance limits of the Mineral Resource categories are presented in Table 11.3.


Mineral Resource Category	Lower Distance (Ft)	Upper Distance (Ft)
Measured	0	660
Indicated	660	1,320
Inferred	1,320	5,280

Table 11.3. Mineral Resource category distances.

Measured Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the average distance between quality drill holes is less than or equal to 660 feet. Much of the structural data has been tightened to a density of 660-feet. Much of this drilling data was collected by Coteau using known sampling methods and surveying methods. Due to the level of control and oversight during collection of this drilling data, the resulting resource estimates have a high level of confidence by the QP and a low level of uncertainty.

Indicated Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the average distance between quality drill holes is greater than 660 feet and less than or equal to 1,320feet. Due to the level of control and oversight during collection of this drilling data, the resulting resource estimates have a high level of confidence by the QP and a low level of uncertainty.

Inferred Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the average distance between quality drill holes is greater the 1,320 feet. Modeled values at these distances require a large amount of interpolation between drill holes, however, due to the level uniformity of the structure and quality data of the Freedom Mine coal field along with the confidence of the drilling data, the resulting resource estimates have a moderate to high level of confidence by the QP and a low level of uncertainty.

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11.2 MINERAL RESOURCE ESTIMATES

BASIS FOR MINERAL RESOURCE ESTIMATE

The basis of the Mineral Resource estimates for the Freedom Mine deposit and the methods in which they were prepared are summarized for this item. The S-K 1300 regulations (17 CFR 229.1300) define a Mineral Resource as:

“A concentration or occurrence of material of economic interest in or on the Earth’s crust in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. A Mineral Resource is a reasonable estimate of mineralization, considering relevant factors, such as cut-off grade, likely mining dimensions, location, or continuity, that, with the assumed and justifiable technical and economic conditions, is likely to, in whole or in part, become economically extractable. It is not merely an inventory of all mineralization drilled or sampled.”

In accordance with definitions presented in 17 CFR 229.1300 and guidance from the Committee for Mineral Reserves International Reporting Standards (CRIRSCO), Mineral Resources are divided into three categories as listed below and are ranked by increasing level of confidence. Mineral Resources are reported as in-situ tons such that no adjustments have been made to account for mining recovery or losses.

Inferred Mineral Resources are defined as a Mineral Resource for which quantity and quality are estimated on the basis of limited geological evidence and sampling. Geological evidence is sufficient to imply but not verify geological and quality continuity. Inferred Mineral Resources have the lowest level of confidence determined by the QP.

Indicated Mineral Resources are defined as a Mineral Resource for which quantity and quality are estimated on the basis of adequate geological evidence and sampling such that the QP can apply modifying factors in sufficient detail to support mine planning and evaluation of the economic viability of the deposit. These Mineral Resources may be converted to a Probable Mineral Reserve. Indicated Mineral Resources have a moderate level of confidence determined by the QP, and could be upgraded to a Measure Mineral Resource with further exploration.

Measured Mineral Resources are defined as a Mineral Resource for which quantity and quality are estimated on the basis of conclusive geological evidence and sampling such that the geologic certainty of the Mineral Resource is sufficient to allow the QP to apply modifying factors in detail to support detailed mine planning and final evaluation of the economic viability of the deposit. Measured Mineral Reserves have the greatest confidence defined by the QP, and may be converted to a Proven Mineral Reserve.

The QP based the Mineral Resource estimates presented in Table 11.4 for the Freedom Mine on a stratigraphic geologic model generated from the verified drilling exploration data presented in Section 7.0 of this TRS. The choice of stratigraphic modeling is due to the continuous spatial continuity of the lignite seams.

MINERAL RESOURCE STATEMENT

The categorized Mineral Resources are reported herein. The effective date of Mineral Resource estimates is December, 31, 2021.

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			Quality
			Calorific Value	Moisture	Ash	Sulfur	Sodium in Ash
Mine	Resource Classification	Tonnage	(Btu/lb)	(wt%)	(wt%)	(wt%)	(wt%)
	Measured	322,310,200	6,779	37.64	7.27	0.89	5.62
Freedom Mine	Indicated	8,188,400	6,776	37.92	7.22	0.90	6.36
	Measured + Indicated	330,498,600	6,778	37.64	7.27	0.89	5.63
	Inferred	15,000	6,463	37.84	9.78	1.02	1.59

Table 11.4. Mineral Resource Estimates.

11.3 CUT-OFF QUALITY, ASSUMED COST AND SALES PRICE

Quality limits for the Mineral Resource estimates were discussed under Section 11.1.

Assumed cost and sales price to determine Mineral Resources was previously defined by the stripping ratio and discussed in subsection Generation of Pit Shells for Mineral Resource Estimates of Section 11.1.

11.4 QUALIFIED PERSONS CLASSIFICATION OF MINERAL RESOURCES

The criteria used by the QP to classify Mineral Resources into measured, indicated, and inferred Mineral Resources was previously discussed in subsection Mineral Resource Classification and Uncertainty under Section 11.1.

11.5 UNCERTAINTY IN THE MINERAL RESOURCE ESTIMATES

Uncertainty in the Mineral Resource estimates was previously discussed in in subsection Mineral Resource Classification and Uncertainty under Section 11.1.

11.6 QUALIFIED PERSON’S POTENTIAL INFLUENCES AFFECTING MINERAL RESOURCE ESTIMATES

Due to the confines of the LSA, factors including contract term or likelihood of economic extraction, lignite sales price, and quality parameters/limits have far less risk of being affected than a mineral sold on the open market. Nonetheless some risks still need to be addressed. Additional exploration may positively or negatively affect Mineral Resource estimates. Furthermore, Mineral Resource estimates may be materially affected by a significant change in the assumptions including general mining costs and land control. New regulations may impose additional economic factors, delays to future permit renewals or applications, or restrictions to physical estimation boundaries. Although Coteau has a long-term LSA, numerous regulatory authorities, along with well-funded political and environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation. As a result of such activities, BEPC could prematurely retire certain coal-fired generating units. Any premature facility closure could have a material adverse effect on the mineral resource estimates. The QP is not aware of any specific factors that would currently materially affect the prospect of economic extraction.

SEC S-K 1300 Technical Report Summary

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12.0 MINERAL RESERVE ESTIMATES

12.1 KEY ASSUMPTIONS, PARAMETERS, AND METHODS

The following key assumptions, parameters, and methods describe how the QP converted the mineral resources to mineral reserves. All recoverable lignite required to fulfill the contractual obligations of the LSA are contained within the LOM Plan pit extents (Figure 12.1 Life of Mine Map, located in the Supplemental Figures Attachment). The criteria used to estimate the recoverable reserves contained within the LOM pits as estimated by Coteau include:

–Mining costs of $1.55/mmBTU;

–Minimum minable lignite thickness: 2.5 feet;

–Maximum burden depth: approximately 260 feet;

–Mining dilution parameters defined in Table 13.2

–Lignite density of 80 lb/ft3

–Recovery rates by seam presented in Table 13.3

The price and other economic assumptions used to estimate the recoverable reserves are supported by the existing all-requirements LSA and LOM associated with that contract. Compensation from DCC includes reimbursement of all mine operating costs plus a contractually-agreed fee based on the amount of coal delivered. AVS, LOS and DGC are located directly next to the Freedom Mine (i.e. a mine-mouth operation) and 100% of the required coal to operate AVS, LOS and DGC is sourced from the Freedom Mine. DGC is a coal gasification plant that manufactures synthetic natural gas and produces fertilizers, solvents, phenol, carbon dioxide, and other chemical products for sale. AVS and LOS are mine-mouth coal-fired power generation facilities. Current projected plant lives are through 2045 for DGC and AVS. LOS Unit 1 is projected to run through 2030 and Unit 2 will cease operations in 2040. As stated in the LSA 100% of Coteau’s production is dedicated to DCC and 100% of DCC’s coal requirements for these plants will be from the Coteau.

The LSA eliminates Coteau’s exposure to spot coal market price fluctuations. As a result of the cost-plus nature of the all-requirements LSA and the mine-mouth location of DCC, factors such transportation costs, location and quality of competing coal reserves, and the ability to compete in the market are not relevant considerations in determining the economic feasibility and viability of the coal reserves associated with the Freedom Mine.

Criteria for determination of Mineral Reserve estimate are justified in further details in the discussion of run-of-mine tonnages under Section 13.0 of this TRS.

A workplan forecast is developed to determine the schedule and estimated delivery requirements of DCC by year until the end of the LOM Plan.

To determine initial tonnages for consideration of Mineral Reserves, factors including the maximum economical strip ratios are applied to the geologic model used to define Mineral Resources. Coteau engineers then project mining pits in Carlson mining software following pit design parameters discussed under Section 13.0 of this TRS. Projections are directed to the topography from the lowest mineable lignite seam. Highwalls are projected at 53-degrees and endwalls are projected at 45-degrees. Volumes of burden and lignite tonnages with associated quality parameters are exported to yearly averages by mine area. The exported data is then brought into spreadsheets to summarize topsoil, subsoil, overburden, and coal tons.

The high-level summary then flows through a series of steps to distribute tonnages and volumes to individual equipment within each operational fleet in order to determine equipment hours (total hours). Consideration of allotted volumes include:

–Equipment mechanical and operational availabilities estimated based on historical production;

–Historic production rates of each piece of equipment;

–Fleet capacity including limiting production factors;

–New and/or retiring equipment and;

–Auxiliary equipment allotments.

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The total hours, allotted volumes, tonnages, staff levels and quality by period are the primary inputs for the Freedom Mine financial model.

After the meter hours for each applicable equipment are calculated to deliver the required tonnages by period, historical equipment costs/hr are applied to determine the total equipment costs for that period. The staff levels are calculated from the required equipment hours and current wages are applied to determine the total labor costs for that period.

Historical unit costs including actual machine operated costs and hours, materials and supplies, and fuel are the basis of the financial model. The historic unit costs are escalated using indices tables and forward-looking futures. The escalated units are then applied to the input hours, volumes, and tonnages previously sequenced to forecast operating costs. In addition to general operating costs, costs pertaining to stockpile inventory adjustments, reclamation, royalties, mine closure, and capital projects are projected and escalated accordingly.

The resulting lignite schedule from the financial model based on the specified delivery schedule determine the Mineral Resources that carry through to become Mineral Reserves.

12.2 MINERAL RESERVE ESTIMATES

BASIS FOR MINERAL RESERVE ESTIMATE

Table 12.1 discloses the Mineral Reserve estimates for the Freedom Mine based on the QP’s detailed evaluation of the modifying factors as applied to indicated or measured mineral resources, which demonstrate economic viability of the Freedom Mine property. The estimated Mineral Reserves are in accordance with the definitions of “Mineral Reserve” as describe by the S-K 1300 regulations (17 CRF 229.1300) as:

“A coal reserve is the economically mineable part of a Measured or Indicated coal resource demonstrated by at least a Preliminary Feasibility Study, which includes information on mining, processing, economic and other relevant factors that demonstrate, at the time of reporting, that economic extraction can be justified.”

In accordance with definitions presented in 17 CFR 229.1300, and guidance from the Committee for Mineral Reserves International Reporting Standards (CRIRSCO), Mineral Reserves are divided into two categories as listed below and are ranked by increasing level of confidence.

Probable Mineral Reserve is the economically mineable part of an indicated and, in some cases, a measured mineral resource. The confidence in the Modifying Factors applying to a Probable Mineral Reserve is lower than that applying to a Proven Mineral Reserve.

Proven Mineral Reserve is the economically mineable part of a measured mineral resource and can only result from conversion of a measured mineral resource. A Proven Mineral Reserve implies a high degree of confidence in the Modifying Factors.

Modifying factors were applied to convert Mineral Resources into Mineral Reserves. These include, but are not restricted to, mining, processing, infrastructure, economic, marketing, legal, environmental, social and governmental factors.

The reference point at which Mineral Reserves are defined, is the point of sale to the DCC. This location is inside Coteau’s Coal Handling Facility where the certified conveyor belt scales weigh the number of tons of lignite delivered to either DGC or AVS.

This disclosure of Mineral Reserves is based upon the QP's preliminary feasibility study (pre-feasibility or PFS), as defined in 17 CFR Part 229.1300, which includes and supports the QP’s determination of Mineral Reserves.

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The LOM plan included annual stripping and lignite production qualities and quantities. Annual production costs were estimated based on the mine plan quantities, surface mining methods, equipment fleets in use, and unit prices that have been proven by historical production at the Freedom Mine. The current mining methods, used at the Freedom Mine since inception, are planned to continue until enough lignite reserve is depleted to fulfill the contractual obligations of the LSA for fuel supply to DCC.

12.3 CUT-OFF QUALITY AND SALES PRICE

Cut-off quality and price were previously discussed in Section 12.1.

12.4 MINERAL RESERVE STATEMENT

The effective date of Mineral Reserve estimates is December, 31, 2021.


			Quality
			Calorific Value	Moisture	Ash	Sulfur	Sodium in Ash
Mine	Reserve Classification	Tonnage	(Btu/lb)	(wt%)	(wt%)	(wt%)	(wt%)
	Proven	253,946,500	6,779	37.70	7.19	0.89	5.12
Freedom Mine	Probable	3,552,300	6,756	38.29	6.78	0.84	5.40
	Total	257,498,800	6,779	37.71	7.19	0.88	5.12

Table 12.1. Mineral Reserve Estimates.

12.5 MULTIPLE COMMODITY MINERAL RESERVE

The Freedom Mine is a single commodity Mineral Reserve.

12.6 QUALIFIED PERSONS OPINION ON RISK FACTORS THAT COULD AFFECT MINERAL RESERVE ESTIMATES

The Freedom Mine has been in operation for over 38 years. Since this is a well-established operation, the deposit, mining, and environmental aspects of the Project are very well understood. The knowledge for the Freedom Mine is based on the collective experience of personnel from Coteau’s site operations and technical disciplines gained during years of lignite mining. This knowledge is supported by years of production data and observations at the Freedom Mine.

Risks include changes in customer demand for any reason, including, but not limited to, dispatch of power generated by other energy sources ahead of coal, fluctuations in demand due to unanticipated weather conditions, regulations or comparable policies which may promote planned and unplanned outages at the customer’s plants, economic conditions, including an economic slowdown and a corresponding decline in the use of electricity, governmental regulations and/or inflationary adjustments which could have a material adverse effect on Coteau's mineral reserve estimates.

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At the time of this TRS, the QP is not aware of any specific factors that would currently materially affect the prospect of economic extraction.

Uncertainty in the Mineral Resource estimates was previously discussed in in subsection Mineral Resource Classification and Uncertainty under Section 11.1.

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13.0 MINING METHODS

The lignite at the Freedom Mine surface mining operation is recovered using dragline and conventional truck and shovel mining methods due to the proximity of the lignite to the surface and the physical characteristics of the deposit. Mining operations includes; suitable plant growth material (SPGM) removal, replacement and storage, overburden removal, lignite production, and spoil backfill and grading. In the development phase, drainage and water control were established (see Water Management under Section 17.0), and then the required infrastructure consisting of power, mine office and maintenance facilities, lignite stockpile facilities, and roadways were established.

13.1 ANNUAL AND TOTAL LIGNITE PRODUCTION

The Freedom Mine is designed to supply approximately 14 to 16 million tons of lignite per year but generally produces between 12.5 million and 13.5 million tons of lignite coal annually. All production from the mine is delivered to DCC, a wholly owned subsidiary of BEPC. DCC then sells the coal to DGC (planned through 2045), AVS (planned through 2045), and to LOS (planned through 2040), all of which are operated by affiliates of BEPC (Figure 12.1 Life of Mine Map, located in the Supplemental Figures Attachment).

13.2 TYPE AND GENERAL MINING METHOD

The Freedom Mine is a surface mining operation, which currently encompasses approximately 45,000 acres within the permitted areas. The mineable coal seam is known as the Beulah-Zap bed, ranging from 15 to 22 feet thick, with a weighted average thickness of approximately 18 feet throughout the permit area. The overburden directly above the Beulah-Zap bed ranges in thickness from 25 feet along the cropline, to more than 250 feet in the larger strip ratio areas.

Coteau utilizes standard surface mining techniques to extract coal from the proposed permit area. Mining operations will typically occur in a sequence of seven events: SPGM removal, overburden removal, coal removal, overburden replacement, final grading, SPGM replacement, and revegetation.

The primary overburden removal units for a typical mining sequence at the Freedom Mine include:

–3 – 105 cubic yard, Draglines

–2 - 40 and 60 cubic yard, Electric-powered shovels

–4 - 18 cubic yard, Hydraulic excavators

–2 – 45 cubic yard, Front-end loaders

–2 – 30 cubic yard, Front-end loaders

–21 – 200 and 240 ton, Overburden end dump trucks

–6 – 32 cubic yard, tractor scrapers

–15 – Track Bulldozers

SPGM will generally be removed by hydraulic excavators and front-end loaders loading trucks, as well as by tractor-scrapers and track dozers. The SPGM will either be stockpiled or directly respread onto regraded areas.

Overburden removal includes the removal of any material between the SPGM and the mineable coal seam. Overburden removal is accomplished with the use of draglines, electric and hydraulic truck-shovel fleets, tractor-scrapers, or other auxiliary equipment. The truck-shovel fleets will be used for pre-benching as well as for uncovering pits along the cropline where shallow cover and steep slopes prohibit the use of the draglines. The Freedom Mine currently uses two different dragline digging methods: single-pass method and spoil side method. In the single-pass method, the overburden can either be removed down to the dragline level as shown in Figure 13.1, or the dragline can remove all the overburden in low cover areas where a truck shovel fleet is not necessary as shown in Figure 13.2. In the spoil side method, the dragline removes the overburden by digging the pit in two passes. The first pass on the highwall side of the pit as shown in Figure 13.3. The dragline then crosses the pit and removes the remaining overburden above the coal from the spoil side as shown in Figure 13.4.

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Once all overburden has been removed, the coal surface is then cleaned and drilled in preparation for blasting. The coal is blasted to a size that can be most effectively loaded into the haul trucks. Coal will be loaded by either excavator or front-end loader, and hauled by trucks.

After the coal is removed, overburden from the next pit is then spoiled into the empty pit, and the mining operation evolves into a reclamation operation. Spoils grading will then occur to return the land back to approximate pre-mining topography. After regrading has been completed, SPGM is then respread before the land is put back into productive use following state regulation requirements. The NDPSC requires that areas must be reclaimed within three years subsequent to coal removal.

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Figure 13.1. Range Diagram – Single-pass method with truck/shovel pre-bench

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Figure 13.2. Range Diagram – Single-pass method with dragline chop cut

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Figure 13.3. Range Diagram – Spoil-side method step 1

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Figure 13.4. Range Diagram – Spoil-side method step 2

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13.3 RUN OF MINE TONNAGES

Recoverable Run of Mine (R-O-M) tonnages at the Freedom Mine meet the following conditions:

–Minimum mining thickness: 2.5 ft;

–Maximum overburden depth: approximately 260 feet;

–Average lignite density: approximately 80 lb/ft3

The average lignite quality on an As Received (AR) basis through the LOM is projected to be:


Calorific Value (Btu/lb)			6,728
Moisture (wt%)			35.56
Ash (wt%)			9.22
Sulfur (wt%)			0.85
Sodium in ash (wt%)			4.54

Table 13.1. Projected Life of Mine Quality.

Mining dilution is determined by an analysis of the geologic model, the coal core data, and the as-delivered coal analyses from the customer’s plant. Roof and floor samples from the coal cores have been periodically collected and analyzed. Statistical analysis has shown that the quality parameters in the roof and floor samples are much more variable than those in the coal seams. Due to this variability, the roof and floor analyses have been used to develop average qualities, with typical distribution ranges.

The geologic model based on the coal core data is evaluated to establish average yearly coal qualities, based on the actual historical yearly mining areas. These yearly coal qualities (from the model) are then compared to the yearly as-delivered analyses from the customer’s plant. Adjustments are made to the thickness of the roof and floor included, as well as, the average roof and floor quality (within the distribution ranges). This process is periodically repeated to update the data and account for changes in the mining and sampling processes and local geology.

It should be noted that this procedure of estimating mining dilution is also including the sampling bias in the customer’s plant’s coal sampling systems and other plant specific variables. This means that the dilution estimates are designed to incorporate the biases and variables within the specific power plant.

Dilution parameters are applied to all lignite seams and are outlined herein:

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Structural (Roof and Floor)
	Loss (ft)	0.50
	Gain (ft)	0.25

Quality (Roof and Floor) (EMA)
	Density (lb/ft3)	150
	Calorific Value (Btu/lb) (MAF)	10,000
	Moisture (wt%)	23.00
	Ash (wt%) (Dry)	90.00
	Sulfur (wt%)(MAF)	1.00

Quality (Roof and Floor) (WMA)
	Density(lb/ft3)	150
	Calorific Value (Btu/lb) (MAF)	10,000
	Moisture (wt%)	20.00
	Ash (wt%)(Dry)	85.00
	Sulfur (wt%)(MAF)	1.00

Table 13.2. R-O-M Dilution Parameters.


Seam			Recovery Rate
UBE1			85%
UBE2			85 %
UBEU			90 %
LBE3			85 %
LBE4			90 %
LBEU			90 %
BEUH			90 %

Table 13.3. Recovery Rates by Seam.

13.4 ENGINEERING STUDIES – DESIGN PARAMETERS

PIT DESIGN

In reference to the 1981 geotechnical engineering report “Ground Stability Study, Beulah-Hazen Area, Mercer County, North Dakota”, prepared for Coteau, a factor of safety of 1.3 is prudent for the design of safe, efficient, and economical highwalls. Actual observed field conditions have closely mirrored the stability calculations in that study for over the past 38 years.

If the overburden consists of consolidated claystone or siltstone, dragline highwall angles of 30 to 60 degrees are used with a nominal design depth of 90 feet. Highwall heights can range up to 120 feet in localized areas to maintain bench grades in areas of steeply dipping coal. Using the charts in the geotechnical report, a factor of safety of 1.6 is

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achieved with a 90-foot-high, 60-degree highwall, and a factor of safety of 1.4 is achieved with a 120-foot highwall. These designs are within the prudent limits established by the geotechnical engineering report.

If the spoil consists of claystone or sandstone, the draglines may be utilized for spoil side digging with a factor of safety of 1.2 for low-walls. Low -wall angles typically range from 25-36 degrees with varying bench heights. With a 30-degree angle, bench heights of 110 feet to 60 feet can be achieved with factors of safety ranging from 1.2 to 1.5, depending on material. If the material consists of claystone, the low-wall angle can be increased to 35 degrees, and a bench height of up to 80 feet can safely be achieved at a factor of safety of 1.2. Crossings from highwall to spoil side are typically 175 feet wide.

In areas where the overburden is not consolidated claystone or siltstone, a 25-foot-wide offset bench will be built for every 50 feet of highwall height. The benches will replace the existing method of laying the highwall back in areas with less favorable ground conditions. Using a maximum bench height of 50 feet with an overall highwall angle of 45 degrees will increase the factor of safety to at least 1.7.

Dragline pits are typically designed 140-160 feet wide. The pit widths vary depending on the depth of coal, highwall angles, etc. These pit widths are maintained to economically remove the overburden to the dragline’s capacity and also provide enough room for safe coal removal operations. Dragline benches are maintained at 250 feet wide in areas where the truck/shovel fleet are pre-benching for the dragline and when the dragline is taking chop cut to build their own bench. Depending on the type and quality of material, highwall angles vary to reach a factor of safety of at least 1.3.

In shovel workings, overall highwall angles are maintained similar to the dragline highwalls. The characteristics of the shovel, however, cause it to dig more steeply on each level or bench. Bench heights range from 30 to 50 feet depending on overburden quality and size of the machine used. Offset benches of at least 25 feet are employed to maintain the overall angle. Offset benches are also used to catch falling material in areas where loose material cannot be scaled or removed from upper level walls.

Spoil is sloped at a safe angle of repose, which in general is between 25 and 36 degrees. Spoil stability is greatly affected by the surface on which the spoil is dumped. The pit floor is cleaned of any water, snow, and mud prior to spoil placement. The floor is also ripped and/or tipped away from the highwall.

The truck/shovel fleet generally digs most boxcuts, thus minimizing dragline boxcut spoil. However, if the dragline does spoil boxcut material, a buffer (typically 50 to 100 feet) will be left between the toe of the boxcut spoil and the highwall crest to prevent material from failing into the pit.

Typical highwall angles with the respective factors of safety can be found in Figures 13.5, 13.6, and Figure 13.7.

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Figure 13.5. 45-degree highwall factors of safety

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Figure 13.6. 55-degree highwall factors of safety

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Figure 13.7. 60-degree highwall factors of safety

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SPOIL STABILITY STUDIES

The initial spoil stability study titled “Slope Stability Study for Coteau Properties” by Lyall Workman of Bauer, Calder & Workman Inc. was completed in September 1984. This study pertains to spoil stability which influences operation plans for production and reclamation. The most common spoil failure is a rotational failure. A rotational failure occurs when the toe of the spoil is weakened, causing the factor of safety to be less than 1.0 resulting in a failure. These failures occur when poor floor conditions are observed, water saturates the toe of the spoil, or when spoil is overfilled. The Freedom Mine typically experiences claystone material with isolated areas of glacial till and sandy materials. The stability nomograph for claystone spoil can be found in Figure 13.8.

Figure 13.8. Stability nomograph for claystone spoil

The Freedom Mine experienced a spoil failure that occurred in August of 2010. The Freedom Mine requested Barr Engineering Company (Barr) to perform a slope stability study for the spoil failure. The slide was substantial both in length and in distance back into the spoils. Truck/shovel spoil that was being hauled to a location in the spoils

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behind the active dragline spoil ridge was included in the failure. The back-failure plane was about 290 feet back into the pre-strip spoil.

An analysis was performed for the spoil pile to determine the in-situ conditions which caused the failure in the spoil pile. Samples of the spoil were taken to determine the properties of the spoil such as the shear strength, triaxial shear, direct shear, and unconfined compression testing. After soil testing was completed, a slope stability model was developed in GEO-SLOPE. The GEO-SLOPE modeling program can take several different approaches to define where the slop failure surface occurs. Two modes of failure, block and circular (rotational), were modeled. Examples of the two different models showing circular (rotational) failure and block failure can be seen in Figures 13.9 and 13.10, respectively.

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Figure 13.9. Modeled circular (rotational) failure with factor of safety equal to 0.987

Figure 13.10. Modeled block failure with factor of safety equal to 0.931

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The spoil failure study concluded that the failure that occurred in MA1 was a block failure. Contributing factors to the block failure were a weak saturated plane in the pit floor consisting of a thin underclay and kicker seam. When the underclay and kicker seam are removed, the spoil piles become more stable and the truck dump soils do not need to be placed as far back to achieve a stable configuration. The total spoil is designed to have a factor of safety greater than 1.2. Different designs are required for good and poor floor conditions. Figures 13.11 and 13.12 show the findings of the study for good and poor floor conditions and the design parameters that should be taken to reach an adequate factor of safety of 1.2.

Figure 13.11. Design parameters for good floor conditions

Figure 13.12. Design parameters for poor floor conditions

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13.5 HAUL ROADS, RAMPS AND DRAGLINE WALKWAYS

Typical sections for haul roads, spoil ramps, highwall ramps, and dragline walkways are presented in Figure 13.13. Haul roads and spoil ramps are typically designed to a width of 90 to 100 feet to allow for two-way traffic. In some circumstances, temporary one-way roads may be established with proper signage. Dragline walkways must be a minimum of 120 feet wide.

Figure 13.13. Typical Haul Road Cross-Section

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13.6 PERSONNEL AND MAJOR EQUIPMENT

The Freedom Mine employs approximately 110 full-time maintenance staff, 250 full-time equipment operators, and 82 full-time staff. In addition to the full-time employees there are 40 part time or seasonal employees that work 6-8 months of the year as well.

A list of major and auxiliary equipment used at the Freedom Mine is shown below and will be used, as needed, for all aspects of the operations.

3 Draglines (105 yard)

15 Bulldozers (140 to 850 hp class)

2 Cable Movers

7 Cable Moving Tractors

2 Front-End Loader (45 cy class)

2 Front-End Loader (30 cy class)

1 Explosives Trucks

1 Coal Drills

1 Overburden Drill

5 Bulldozers (rubber-tired)

8 Bottom-Dump Coal Haulers (300 ton and 240 ton class)

2 Overburden Shovels (60 cy and 40 cy class)

10 Overburden Trucks (240 ton class)

11 Overburden Trucks (190 ton class)

2 Sheepsfoot Compactors with Tractors

10 Road Graders

5 Water Trucks (14,000 to 40,000 gallon class)

2 Dump Trucks (15 ton class)

3 Front-end Loader (6 yard class)

7 Hydraulic Backhoes (1, 2, and 18 cy yard class)

4 Supply Trucks (flatbed)

1 Mobile Crane (300 ton class)

1 Mobile Crane (200 ton class)

1 Mobile Crane (60 ton class)

2 Lowboy (250 ton class)

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2 Lowboy (55 ton class)

1 Electrical Maintenance Truck

1 Portable Air Compressor

1 Fuel Truck

3 Welding Trucks

3 Service and Lube Trucks

1 Tire Maintenance Vehicle

2 Fuel Tank Farms

2 Forklifts (1½ ton class)

2 Field Maintenance Trucks

14 Portable Pit Pumps (diesel)

4 Portable Pumps (electric)

3 Portable Generators

4 High Volume Water Pumps

2 Flocculation Plants

55 Pickups

6 Vans

1 Ambulance

7 Scrapers (32 yd class)

Lot Miscellaneous Seeding Equipment

20 Portable Pit Lights

2 Articulated Trucks (40 ton class)

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14.0 PROCESSING AND RECOVERY METHODS

No mineral processing is performed.

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15.0 INFRASTRUCTURE

The Freedom Mine public utility lines and facilities locations are presented in Figure 15.1 Infrastructure Map, located in the Supplemental Figures Attachment.

Coteau purchases power from Roughrider Electric, a cooperative of BEPC. A 69kV powerline leaves a switchyard located directly west of AVS. The power line then runs underground to the permanent substation located between Coteau and AVS’s facilities. From there, a 69kv line runs west to a substation located west of County Road 15 to feed MA3. Then runs south parallel with County Road 15 on the west side road to a substation that feeds MA1. The EMA is also fed from the permanent substation. A 69kv line runs east out of the permanent substation paralleling Coteau’s haul road that accesses the EMA. The 69kV line then runs around the south side of the EMA and runs north to a centralized area in advance of the EMA.

Coteau’s Shop/Office complex is fed from the main permanent substation from AVS’s switchyard.

Coteau’s coal handling facilities are fed from the main permanent substation from AVS’s switchyard. The line runs east out of the permanent substation until it intersects 60th Ave NW. The line then turns south to parallel 60th Ave NW to the Boot Hill Substation where power is distributed to the East Truck Dump, drive house, and coal handling facilities located directly south east of AVS.

Potable water for the mine office facilities is supplied by the Southwest Water Authority.

The Freedom Mine utilizes an aerobic sanitary waste treatment lagoon system for office effluent. The lagoon system is regulated by the ND Department of Environmental Quality under NDPDES Permit ND0025038. Effluent from portable restrooms is collected by licensed septic pumpers and disposed of according to state law.

An appropriated surface water source, Lake Sakakawea, is used for washing equipment in the facilities wash bay and irrigating the lawn around the office facility. Fire hydrants use recycled water from AVS. All other office water is supplied by the Southwest Water Authority, including several pastures taps for livestock watering.

Sedimentation ponds P-J30-02R and P-D03-02 are permitted for Beneficial Water Use by the ND State Water Commission and serve as the water source for dust suppression. Both sedimentation ponds have a water load-out station used to fill mine water trucks.

Lignite will be mined and transported to the coal handling facility, located directly east of DGC and AVS. The coal can either be stockpiled for future use or be hauled directly to DCC. A system of permanent haul roads are utilized to transport the coal from the pits to the coal handling facilities. An overpass bridge was built in 2006 with the capacity to handle Coteau’s equipment to cross County Road 26 to access the MA1 reserves. The bridge was needed to cross over County Road 26, DGC’s natural gas pipeline, and the railroad that transports coal from the coal handling facility to LOS. To access the EMA, an overpass was constructed on County Road 21 to pass over Coteau’s haul road. To access MA3, the equipment haul road crosses County Road 15 at grade directly west of the office/shop complex. Public access is blocked off in this area to allow for steady traffic flow. Public roads are not used for the transport of lignite to DCC. Mine site haul routes are depicted in Figure 15.1 Infrastructure Map in the Supplemental Figures Attachment.

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16.0 MARKET STUDIES

16.1 MARKETS

As stated previously in Section 5, the Freedom Mine coal reserves are 100% dedicated to DCC. Any market expansion would be the sole responsibility of DCC.

16.2 MATERIAL CONTRACTS

Freedom Mine is a fully developed and functioning mining operation. All aspects of the mining, haulage and delivery of lignite to DCC and affiliates are handled by Coteau. Coteau is a mine-mouth project where the lignite is delivered directly to DCC using conveyors. All production from the mine is delivered to DCC under a long-term LSA. Although the term of the existing LSA terminates in 2027, the term may be extended for two additional periods of five years, or until 2037, at the option of the Coteau. Under the LSA, Coteau receives a contractually-agreed fee based on the amount of lignite delivered. While Coteau is responsible for all mine operations, DCC is responsible for funding all mine operating costs and provides all of the capital required to build and operate the mine. This contract structure eliminates exposure to spot coal market price fluctuations. No other material outside contracts are required to provide this service. No material contacts with affiliated parties are in place. Coteau is an active operation and all material contracts are in place for the continued operation of the mine.

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17.0 ENVIRONMENTAL STUDIES, PERMITTING, AND PLANS, NEGOTIATIONS, OR AGREEMENTS WITH LOCAL INDIVIDUALS OR GROUPS

17.1 ENVIRONMENTAL AND BASELINE STUDIES

Environmental resource baseline studies must be conducted prior to the issuance of a surface coal mining permit by the NDPSC. These baseline studies collect information for a variety of areas, including:

–Geology

–Surface Water Hydrology

–Ground Water Hydrology

–Soil Resources

–Alluvial Valley Floors

–Fish and Wildlife Resources

–Climatological Data

–Air Resources

–Aquatic Ecology

–Streams and Wetlands

–Terrestrial Ecology

–Threatened and Endangered Species

–Land Use

–Cultural and Historical Resources

–Transportation Facilities

–Public Health

–Hazardous and Solid Waste

–Prime Farmland

The results of the geological baseline studies are detailed in Section 6.0. Additionally, the results of the surface and groundwater baseline studies and geotechnical studies are documented in Sections 7.3 and 7.4, respectively.

17.2 WASTE DISPOSAL, SITE MONITORING, AND WATER MANAGEMENT

WASTE DISPOSAL

No processing of lignite occurs at the Freedom Mine; therefore, no lignite processing or tailing wastes have been or will be generated.

SITE MONITORING

The Freedom Mine is required to conduct routine groundwater, surface water and soil sampling in accordance with SMCRA and NDPDES permit requirements. Surface and groundwater monitoring occur both within the active mine area as well as in adjacent, undisturbed areas upstream and downstream of the active mining operations. The Freedom Mine also conducts routine soil sampling to ensure the reclaimed environment meets regulatory chemical and textural requirements. The water and soil data are submitted to NDPSC and NDDEQ in accordance with permit requirements.

The Freedom Mine will continue to monitor surface water, groundwater, and soils in accordance with all permit requirements until such time mining and reclamation activities are complete and NDPSC has released the entire project from the reclamation performance bond requirements. This release can only happen once the Freedom Mine

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has quantitatively demonstrated that the reclaimed areas meet performance criteria detailed in the mining permit. Once the reclamation performance bond is released, the Freedom Mine will have no further site monitoring requirements.

WATER MANAGEMENT

The Freedom Mine manages stormwater by constructing large, strategically located sedimentation ponds. The sedimentation ponds are constructed in accordance with permit requirements to retain a 10-year, 24-hour storm event. Once the retained water meets NDPDES water quality requirements, the water is released back into the natural system. The results of the NDPDES monitoring are reported to NDPSC and NDDEQ. The Freedom Mine also maintains a general permit to authorize discharge of stormwater associated with mining, extraction or paving materials. This permit is used for areas of small runoff, such as roads, which are not contained within the watershed of a sedimentation pond. For these areas, a Storm Water Pollution and Prevention (SWPP) plan has been developed to discuss Best Management Practices (BMPs) implemented for the reduction of erosion and sedimentation as well as a Spill Prevention, Control, and Countermeasures (SPCC) plan.

17.3 PERMITS

The Freedom Mine is operating under a total of five surface coal mining permits: NACT-1801, NACT-0201, NACT-0401, NACT-9001, NACT-9101. The permits were issued by the NDPSC under delegated authority of the United States Department of the Interior, Office of Surface Mining Reclamation Enforcement (OSMRE) under the Surface Mining Control and Reclamation Act (SMCRA).

PERMIT STATUS

In addition to the mining permits, the Freedom Mine is required to obtain and maintain numerous other regulatory permits and approvals:

•MSHA 32-00595 - Freedom Mine Identification Number

Issued: January 16, 1978

Mine Safety and Health Administration

U.S. Department of Labor

P. O. Box 25367

Denver, Colorado 80225-0367

•Ground Control Plan

ID #32-00595

Effective: November 30, 1992

Updates Approved: June 8, 2009 and February 28, 2014

Mine Safety and Health Administration

U.S. Department of Labor

P. O. Box 25367

Denver, Colorado 80225-0367

•NDPDES Discharge Permit ND-0025038

Issued: January 1, 1992

Renewed: January 1, 2022

North Dakota Department of Environmental Quality

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Division of Water Quality

4201 Normandy Street

Bismarck, North Dakota 58503-1324

•NDPDES Storm Water Permit NDR32-0017

Issued: July 1, 1994

Renewed: July 1, 2020

North Dakota Department of Environmental Quality

Division of Water Quality

4201 Normandy Street

Bismarck, North Dakota 58503-1324

•Air Pollution Control Permit to Operate #085004

Issued: November 17, 1993; Amended February 7, 1995

Renewed: October 21, 2021

North Dakota Department of Environmental Quality

Division of Air Quality

4201 Normandy Street

Bismarck, North Dakota 58503-1324

•Air Pollution Control Permit to Construct

Issued: February 24, 1978

Amendment 1: May 29, 1979

Amendment 2: October 31, 1979

Amendment 3: August 14, 1981

Expansion Area: December 7, 1992

EMA Secondary Coal Crusher: September 12, 1994

North Dakota Department of Environmental Quality

Division of Air Quality

4201 Normandy Street

Bismarck, North Dakota 58503-1324

•Permit for Solid Waste Management Facility - 0343

Issued: June 16, 2009

North Dakota Department of Environmental Quality

Division of Air Quality

4201 Normandy Street

Bismarck, North Dakota 58503-1324

•Temporary Water Use Permit #ND2021-20733

Issued: October 1, 2021

Perfected Water Use Permit #3050

Issued: February 27, 1985

Perfected Water Use Permit #4217

Issued: October 25, 1999

Perfected Water Use Permit #4384

Issued: October 25, 1999

Perfected Water Use Permit #5043

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Issued: November 3, 1999

Perfected Water Use Permit #5262

Issued: October 30, 1998

Transferred to ND Game and Fish Department – June 24, 2004

Perfected Water Use Permit #5384

Issued: February 14, 2000

Dam Construction Permit #1475

Issued: November 2, 1998

North Dakota State Water Commission

900 East Boulevard Avenue

Bismarck, North Dakota 58505-0850

•Aeronautical Study – 2005-AGL-2925-OE, 2005-AGL-2926-OE, 2005-AGL-2929-OE, 2005-AGL-2930-OE, 2005-AGL-2931-OE, 2005-AGL-2932-OE, 2005-AGL-2933-OE, 2005-AGL-2934-OE, 2005-AGL-2935-OE, 2005-AGL-2936-OE, 2005-AGL-2937-OE, 2005-AGL-2938-OE, 2005-AGL-2939-OE, and 2005-AGL-2940-OE

Issued: June 7, 2005

Aeronautical Study – 2011-AGL-7238-OE

Issued: November 7, 2011

Federal Aviation Administration

SW Regional Office

Obstruction Evaluation Group

2601 Meacham Boulevard

Fort Worth, Texas 76137

•State Coal Exploration Permit

Issued: July 14, 2021

North Dakota Geological Survey

North Dakota Industrial Commission

600 East Boulevard Avenue

Bismarck, North Dakota 58505-0840

•Federal Coal Exploration License NDM 90166 and NDM 90322

Issued: September 15, 2000 and October 17, 2000

U.S. Department of the Interior

Bureau of Land Management

5001 Southgate Drive

Billings, Montana 59101

•Conditional Use for Coal Excavation and Mining, and Certificate of Zoning Compliance

Case 1041 – Issued April 3, 1979 (For Permit NACT-8102)

Case 1155 – Issued April 1, 1980 (For Permit NACT-8102)

Case 8119 - Issued July 7, 1981 (For Permit NACT-8102)

Case 8340 - Issued August 2, 1983 (For Permit NACT-8203)

Case 8410 - Issued June 5, 1984 (For Permit NACT-8401)

Case 86-06-02 - Issued July 1, 1986 (For Permit NACT-8503)

Case 87-04-05 - Issued May 12, 1987 (For Permit NACT-8601)

Case 90-11-01 - Issued December 4, 1990 (For Permit NACT-9001)

Case 94-02-01 - Issued March 3, 1994 (For Permit NACT-9001)

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Case 92-02-02 - Issued April 7, 1992 (For Permit NACT-9101)

Case 94-02-02 - Issued March 3, 1994 (For Permit NACT-9101)

Case 95-12-02 - Issued January 5, 1996 (For Permit NACT-9101)

Case 97-11-01 – Issued December 2, 1997 (For Permit NACT-9101) (Harmony Lake)

Case 01-01-01 – Issued February 6, 2001 (For Permit NACT-9101)

Case 07-05-03 – Issued June 7, 2007 (For Permit NACT-9101)

Case 95-12-01 - Issued January 5, 1996 (For Permit NACT-9501)

Case 99-01-01 – Issued February 2, 1999 (For Permit NACT-9501)

Case 01-11-01 – Issued December 4, 2001 (For Permit NACT-9501)

Case 02-12-01 – Issued February 4, 2003 (For Permit NACT-0201)

Case 05-02-01 – Issued July 7, 2005 (For Permit NACT-0401)

Case 08-04-01 – Issued May 7, 2008 (For Permit NACT-0401)

Mercer County Board of Commissioners

P.O. Box 39

Stanton, North Dakota 58571

•Federal Explosives License/Permit

License Number: 3-ND-057-33-2A-00163

License Type: User of Explosives

U.S. Department of Justice

Bureau of Alcohol, Tobacco, Firearms, and Explosives

Federal Explosives Licensing Center

244 Needy Road

Martinsburg, West Virginia 24505-9431

•Wetland Drainage Permits

#2642 - Issued April 5, 1990

#2655 - Issued March 14, 1991

#2682 - Issued December 9, 1993

#2695 - Issued April 14, 1994

#2741 - Issued January 11, 1996

#2742 - Issued January 11, 1996

#2956 – Issued February 8, 2002

#2995 – Issued August 14, 2003

Office of the State Engineer

900 East Boulevard Avenue

Bismarck, North Dakota 58505-0850

•Department of the Army Individual Permit

Issued: June 29, 2016

U.S. Army Corps of Engineers

North Dakota Regulatory Office

3319 University Drive

Bismarck, North Dakota 58504

•Approval to remove diversion in the NW¼ Section 3, T145N, R87W

Granted April 17, 2001

Design approval for rerouted waterway in Section 9, T145N, R86W

Granted April 17, 2001

Mercer County Water Resource Board

P.O. Box 488

Hazen, North Dakota 58545

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17.4 RECLAMATION BOND REQUIREMENTS

Freedom Mine is required to post a performance bond per NDCC 38-14.1-16 of the regulations. Bonding is calculated based on a consolidated mine wide worst-case scenario with an estimated reclamation cost of $174.4 million. The Freedom mine has secured $186 million through a third-party guarantee and collateral bond.

17.5 PLANS, NEGOTIATIONS, OR AGREEMENTS WITH LOCAL INDIVIDUALS OR GROUPS

The Freedom Mine has secured agreements with all third parties that are necessary to conduct mining operations in accordance with applicable law.

17.6 MINE CLOSURE PLANS

The projected plant lives and subsequent LOM plans are projected to continue operations through 2045. Although the mineable lignite within the Freedom Mine coal field will not be exhausted, the production period is tied to the current LSA and/or LOM Plan with DCC and is based on the projected life of the plants which are expected to operate until 2045.All mine closing is funded by DCC in a reclamation trust account, current estimated future mine closing expenses and accumulated funds total $307 million. Following the closure of BEPC’s plants and the subsequent closure of the mine, Coteau will be required to complete remediation and reclamation of all mined areas. Adequate material will be stockpiled to fill the final highwalls and all necessary regrading will commence after final coal removal to satisfy all requirements in the approved mining permits. Final reclamation and closure activities vary by mine area. The NDPSC permits for mining areas detail post production reclamation activities and long-term management plans for mined lands and all disturbed areas.

17.7 QUALIFIED PERSON’S OPINION OF ADEQUACY OF CURRENT PLANS

Although the term of the existing lignite sales agreement terminates in 2027, the term may be extended for two additional periods of five years, or until 2037, at the option of Coteau. Coteau currently has all permits in place for the Freedom Mine to operate through 2031. Permit expansions required to extend the life of the mine through 2045 will be acquired as needed. Absent of any regulatory changes out of Coteau’s control, the QPs do not anticipate hurdles for approval of future permit applications. The QPs base this opinion on the mine’s demonstrated success meeting regulatory requirements. No NOVs have been issued at the Freedom Mine in more than ten years. Proper monitoring plans in accordance with QA/QC procedures have been in place at the Freedom Mine since the mine’s inception and are documented through regular reporting to NDPSC. Furthermore, appropriate bonding and closure plans are in place. As the existing lignite sales agreement between Coteau and DCC is in effect through 2037, any tons within the LOM plan through 2037 are considered a reserve. Tons remaining between 2037 and 2045 are considered a resource.

17.8 DESCRIPTION OF ANY COMMITMENTS TO ENSURE LOCAL PROCUREMENT AND HIRING

Purchasing endeavors to place orders with regards to dependability and service records of the supplier, the nature of the guaranty and warranty of the product, its price, and quality. Preference is given to suppliers who are developing new and improved products or equipment, or designing and developing a special product, specifically for the Freedom Mine. Consideration is also provided to local suppliers near the Freedom Mine. Suppliers must have a reputation of adhering to specifications and delivery schedules.

Open positions at the Freedom Mine are posted in local and regional papers as well as on applicable online recruitment websites. Coteau also participates with regional state job fairs, recruit on local college campuses and participate in local community sponsored activities.

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18.0 CAPITAL AND OPERATING COSTS

18.1 OPERATING COSTS

Annual production costs were estimated in conjunction with the mining methods discussed in Section 13 to satisfy the contractual terms of the LSA. All costs were estimated based on the most recent LOM tonnage requirement provided by DCC in 2009 and are escalated at various rates depending on the predicted performance of the Consumer/Producer Price Index with 2021 being the base year. Operating costs include operating, maintenance, and staff labor, materials and supplies, fuel, equipment repairs, outside contractors, administration, royalties, and all required taxes.

The model used to estimate the operating costs to a PFS level of study is based on historical costs and performance measures that have been maintained by Coteau since its inception. These costs are reviewed on an annual basis to account for changes in site conditions or the operating plan. This information is then used to estimate the projected costs for the LOM plan until the end of the current LSA in 2037. Table 18.1 provides a summary of the assumptions that were used to develop these projected costs.


	Annual Average
Dragline Overburden*	83,142,000	CY
Truck/Shovel Overburden*	28,945,000	CY
Virgin Stripping Ratio	11.166.46
Delivered Tons	14,167,000	Tons
Lignite cost per Delivered Ton	$ 1.55	/mm BTU

Quality:
Heating Value	6719	BTU/LB
Moisture	36.14%
Sulfur	0.90%
Ash	9.01%

*Includes re-handle

Table 18.1. Cost Assumptions

All costs including mine development, overburden removal, severing of lignite, reclamation, maintenance and handling of stockpiled lignite and delivery to the neighboring facilities along with the necessary maintenance required to keep all equipment operating safely and efficiently are paid by DCC as required under the LSA. Coteau is then paid a profit based on delivered tons. All mine closing costs are also required to be paid by DCC under the LSA. Each month of production, DCC records a liability based on the ARO (Asset Retirement Obligation) calculation. As mine closing dollars are expended, Coteau is reimbursed from DCC.

The total cost of coal over the remaining term of the LSA is shown in Table 18.2. Cost of Coal. Historical data was used to determine the estimated ratio of direct and indirect costs. Indirect costs include; support wages and benefits, medical insurance, power (demand), outside services, short term rentals, miscellaneous, property tax, coal lease maintenance, property and liability insurance, office costs, travel costs, depreciation and amortization, and interest expense. Direct costs include; workforce wages and benefits, supervisory wages and benefits, supplies, fuel, major repairs, power (usage), outside services, short term rentals, royalties, severance tax, federal reclamation fee, stockpile variance, and management fee/profit.

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Table 18.2. Cost of Coal.

18.2 CAPITAL COSTS

Capital Costs were estimated to a PFS level of study based on vendor quotes, historical land purchases, mine development costs, mitigation costs and other costs. Capital costs include equipment expenditures, additional mine area development, and land acquisition costs. Future capital costs through 2037 to fulfil the LSA are estimated to total $218.1 million. All capital costs incurred by Coteau are reimbursed by DCC as required under the terms of the LSA. There are risks regarding the capital costs estimates, including escalating costs of raw materials, equipment availability and timing due to either production delays or supply chain gaps. Estimated future annual capital costs are summarized in Table 18.3. Capital Costs. Should the LSA be extended beyond 2037, to reach the end of LOM in 2045, additional capital costs would be required and funded by DCC.

Table 18.3. Capital Costs

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19.0 ECONOMIC ANALYSIS

19.1 KEY ASSUMPTIONS, PARAMETERS AND METHODS

Although the existing LSA terminates in 2027, the term may be extended for two additional periods of five years, or until 2037, at the option of Coteau. As the existing LSA between Coteau and DCC is in effect through 2037, any tons within the LOM plan through 2037 are considered a reserve. Tons remaining between 2037 and 2045 are considered a resource.

A reduction in dispatch of AVS or LOS or premature closure of AVS, LOS and/or DGC would have a material adverse effect on the economic viability of the Freedom Mine reserves. In August 2021, BEPC signed a non-binding term sheet to sell the assets of DGC. As part of the agreement, BEPC indicated that DGC will continue existing operations through 2025. The closing of the agreement is subject to the satisfaction of specified conditions. BEPC is also considering other options for DGC if the transaction with the potential buyer does not close. As this is a non-binding agreement, the current LOM plan assumes DGC operates through 2045.

The analysis of economic viability of the Freedom Mine is supported by the existing all-requirements LSA and LOM associated with that contract. Compensation from DCC includes reimbursement of all mine operating costs plus a contractually-agreed fee based on the amount of coal delivered. AVS, LOS and DGC are located directly next to the Freedom Mine (i.e. a mine-mouth operation) and 100% of the required coal to operate AVS, LOS and DGC is sourced from the Freedom Mine.

DGC is a coal gasification plant that manufactures synthetic natural gas and produces fertilizers, solvents, phenol, carbon dioxide, and other chemical products for sale. AVS and LOS are mine-mouth coal-fired power generation facilities. Current projected plant lives are through 2045 for DGC and AVS. LOS Unit 1 is projected to run through 2030 and Unit 2 will cease operations in 2040. As stated in the LSA 100% of Coteau’s production is dedicated to DCC and 100% of DCC’s coal requirements for these plants will be from Coteau.

The current LOM delivery requirements are based on the most recent projections from DCC. DCC has approved the LOM plan. The approved LOM plan was completed in 2010 dollars. The costs reflected above in Table 18.2. Cost of Coal have been escalated to reflect 2021 dollars.

Key assumptions to escalate the approved LOM plan to 2021 dollars include:

•Wages and benefits restated at current labor rates

•Supply costs restated based on historical vendor price increases

•Current price per ton rates where applicable

•Current mine closing cost study

19.2 ANNUAL CASH FLOWS

The Internal Rate of Return and capital payback period is not applicable due to the ongoing nature of this project and cost-plus feature of the LSA. The cost-plus nature of the LSA provides assurance that all costs incurred by Coteau will be reimbursed by DCC and negates any risk of loss to Coteau, which allows the mine to remain cash flow positive in 2022 and remain so through 2037.

Using the assumptions outlined in Section 18 above, the mine has a cash flow after tax projected to be $302.2MM resulting in a Net Present Value of $148.5MM.

An effective income tax rate of 12% was utilized in calculating income tax expense. This rate differs from the U.S. federal statutory rate primarily due to the benefit from percentage depletion. The benefit of percentage depletion is not directly related to the amount of pre-tax income recorded in a period.

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19.3 SENSITIVITY ANALYSIS

Over the history of the mine, Coteau has performed numerous LOM studies based on various tonnage requirements requested by DCC. Increased tonnage decreases the overall production cost per ton as fixed costs can be spread over additional tons. For every 100,000 ton annual reduction, costs are estimated to increase approximately $0.08/ton. The inverse has also been shown such that for every 100,000 ton annual increase, the overall cost of production is estimated to be reduced by approximately $0.08/ton. As a result, BEPC has historically operated AVS, LOS and DGC at the highest possible production rates.

Coteau’s profit correlates proportionally with the actual increase or decrease in tonnage required for BEPC as compensation from DCC includes reimbursement of all mine operating costs plus a contractually-agreed fee based on the amount of coal delivered. It was assumed all costs in the LOM are economical for DCC based on approval of Coteau’s LOM plan, which was escalated utilizing the key assumptions outlined previously. One of the largest cost components within the plan that fluctuates is diesel fuel. A cost of $2.40 per gallon for diesel price was used. If the cost of diesel goes up 50%, the final average selling price of coal will go from $1.55 per mmBTU to $1.63 per mmBTU, respectively.

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20.0 ADJACENT PROPERTIES

There are no properties adjacent to the Freedom Mine. There is no information used in this TRS that has been sourced from adjacent properties.

The drilling and exploration activities at the Freedom Mine defines the lignite geology, Mineral Resources and Mineral Reserves. Due to this and the relatively simple geology at the Freedom Mine, material changes to the Mineral Resource estimates and Mineral Reserve estimates are not likely if adjacent property information is included in future estimates.

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21.0 OTHER RELEVANT DATA AND INFORMATION

In the QPs opinion, all material information has been stated in the above sections of this TRS.

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22.0 INTERPRETATIONS AND CONCLUSIONS

All data provided in this TRS is appropriate and has been utilized for the start-up, and continual operation of the Freedom Mine. The Freedom Mine has been a producing mine since 1983.

The projected plant lives and the LOM plan are projected to continue operations through 2045. The term of the existing LSA terminates in 2027, although the term may be extended for two additional periods of five years, or until 2037, at the option of Coteau. Coteau currently has all permits in place for the Freedom Mine to operate through 2031. Permit expansions required to extend the life of the mine through 2045, which is the current estimated lives of DGC and AVS, will be acquired as needed.

Due to the confines of the LSA, factors including contract term or likelihood of economic extraction, lignite sales price, and quality parameters/limits have far less risk of being affected than a mineral sold on the open market. Nonetheless some risks still need to be addressed. Additional exploration may positively or negatively affect Mineral Resource estimates. Although rare but possible, unexpected coal subcrops and seam pinchouts can affect tonnage estimates. Furthermore, Mineral Resource estimates may be materially affected by a significant change in the assumptions including general mining costs and land control. New regulations may impose additional economic factors, delays to future permit renewals and applications, or restrictions to physical estimation boundaries. Although Coteau has a long-term LSA, regulatory changes or lower carbon initiatives could affect either Coteau or BEPC. Also numerous regulatory authorities, along with well-funded political and environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation. As a result of such activities, BEPC could prematurely retire coal-fired generating units. Any premature facility closure could have a material adverse effect on the mineral resource estimates.

The QP is not aware of any specific factors that would currently materially affect the prospect of economic extraction. Although, in August 2021, BEPC signed a non-binding term sheet to sell the assets of DGC. As part of the agreement, BEPC indicated that DGC will continue existing operations through 2025. The closing of the agreement is subject to the satisfaction of specified conditions. BEPC is also considering other options for DGC if the transaction with the potential buyer does not close. As this is a non-binding agreement, the current LOM plan assumes DGC operates through 2045.

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23.0 RECOMMENDATIONS

Continue current practices and reconciliations of actual to budget lignite recoveries, qualities, and costs. Update LOM plan projections and economic analyses accordingly.

Additional exploration drilling is recommended to convert any inferred and indicated resources to measured resources. Additional exploration drilling will also be required for future mine permit applications. The cost associated with the additional exploration drilling to improve reserve estimates through 2037 is approximately $3MM to $5.5MM. The cost associated with the additional exploration drilling to improve resource estimates from 2037 to 2045 is approximately $2.5MM. These estimates are already included in future cost projections/LOM Plan.

Coteau currently has all permits in place for the Freedom Mine to operate through 2031. Permit expansions will be required to extend the life of the mine through 2045. The cost associated with the environmental studies needed to expand the permit boundaries to extend the LOM through 2045 is approximately $10MM. These estimates are already included in future cost projections/LOM Plan.

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24.0 ADDITIONAL REFERENCES

Barr Engineering Company. (2011, March). Spoil Failure Investigation.

Barr Engineering Company. (2011, July). Slope Stability Two Pass Method.

Bluemle, J. 1983. Geologic and Topographic Bedrock Map of North Dakota.

CRIRSCO. (2019, November). The International Reporting Template.

Croft, M. G. Groundwater Resources, Mercer and Oliver Counties, North Dakota, Bulletin 56 - Part II. I-II-III - North Dakota Geological Survey, Bismarck, North Dakota, 1973.

NACoal. (1981, June). Ground Stability Study, Beulah-Hazen Area, Mercer County, North Dakota, Geotechnical Engineering Report.

NACoal. (2020, November 30). 2020 Lignite Coal Quality Round Robin.

Workman, L. 1984. Slope Stability Study for Coteau Properties.

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25.0 RELIANCE ON INFORMATION PROVIDED BY THE REGISTRANT

The QPs for this report are employees of the registrant and all information was sourced from the registrant or studies commissioned by the registrant.

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PROPERTY LOCATION

The Freedom Mine is located approximately 7 miles north and 3 miles west of Beulah, North Dakota (ND), in Mercer County, which is approximately 90 miles northwest of Bismarck, ND. The entrance to the mine is by means of a paved road north of the intersection of State Highway 49 and United States Highway 200. The general location of the Freedom Mine is shown in Figure 1.1 (Location of the Freedom Mine). The Antelope Valley Station and the Great Plains Synfuels Plant are located adjacent to the Freedom Mine.

Figure 1.1. Location of the Freedom Mine.

LOCAL RESOURCES AND INFRASTRUCTURE

The towns of Beulah, Hazen, and Stanton along with other smaller communities are within a 40-mile radius of the Freedom Mine and provide a vast supply of the employment base. Employees also comes from the cities of Bismarck, Minot, and Dickinson, all of which are less than 100 miles away from the mine.

The Freedom Mine sources power for mine office facilities and operations from Roughrider Electric Cooperative, and water for the mine office facilities from the Southwest Water Authority. Fuel for equipment is supplied by multiple local. The Freedom Mine has, or is currently constructing, all supporting infrastructure for mining operations.

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North Dakota’s freight rail service is largely provided by Burlington Northern Santa Fe Railway and Canadian Pacific Railway.

LEASES

Coteau holds 380 leases granting the right to mine approximately 34,016 acres of coal interests and the right to utilize about 23,455 acres of surface interests. In addition, Coteau owns in fee about 33,805 acres of surface interests and 4,107 acres of coal interests. The leases and deeds are recorded at the Mercer County courthouse and are a matter of public record. Substantially all of the leases were acquired in the 1970’s and have been replaced with new leases and/or have continuation provisions that generally permit the leases to be continued beyond their fixed terms. The leases obligate Coteau to make payments based on the amount of lignite mined from the subject property. Most royalty rates range from $0.08 - $0.16 per ton of lignite mined. A few leases include annual escalator provisions. Payments also may include surface damage payments and advanced or minimum royalty payments. Production royalties are calculated monthly based on surveys and are generally paid on a quarterly basis, although in certain situations royalties are paid monthly. Table 1.1 Identification of Leases, and Table 1.2 Identification of Acquisitions, shows the name or identifying number of each lease, or sublease, the nature and extent of Coteau’s title to, or interest in, the associated property, and expiration date of each lease. While Coteau’s leases include a primary, or fixed, term (as set forth in Table 1.1), they include continuation provisions that allow for their continuation beyond their primary terms so long as operations and/or reclamation activities are continuing.

Table 1.1 Identification of Leases

Lease Id

Lease Type

Lease Date

Lease Expiration Date

215-01947

Coal Lease

6/1/2006

5/31/2026

2AR-00503

Coal Lease Agreement

10/10/1989

10/9/1999

2AR-00504

Coal Lease Agreement

5/1/1990

4/30/2000

2AR-00505

Coal Lease Agreement

5/1/1990

4/30/2000

2AR-00591

Coal Lease

7/25/1997

6/30/2017

2AR-00597

Surface & Coal Lease Agreement

4/6/2000

4/5/2020

2AR-00598

Surface & Coal Lease Agreement

4/13/2000

4/12/2020

2AR-00599

Surface & Coal Lease Agreement

4/14/2000

4/13/2020

2AR-00600

Surface & Coal Lease Agreement

4/20/2000

4/19/2020

2AR-00601

Surface Lease Agreement

5/10/2000

5/9/2020

2AR-00602

Surface Lease Agreement

5/24/2000

5/23/2020

SEC S-K 1300 Individual Property Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

2AR-00603

Surface & Coal Lease Agreement

8/5/2000

8/4/2020

2AR-00604

Coal Lease Agreement

9/11/2000

9/10/2020

2AR-00606

Surface & Coal Lease Agreement

11/8/2000

11/7/2020

2AR-00612

Surface Lease Agreement

8/20/2001

8/19/2021

2AR-00613

Surface Lease Agreement

9/13/2001

9/12/2011

2AR-00615

Coal Lease Agreement

12/4/2001

12/3/2011

2AR-00616

Coal Lease Agreement

12/10/2001

12/9/2011

2AR-00617

Coal Lease Agreement

12/28/2001

12/27/2011

2AR-00618

Coal Lease

2/28/2002

2/27/2032

2AR-00619

Coal Lease

2/28/2002

2/27/2032

2AR-00620

Coal Lease

2/28/2002

2/27/2032

2AR-00621

Coal Lease

2/28/2002

2/27/2032

2AR-00622

Coal Lease

2/28/2002

2/27/2032

2AR-00623

Coal Lease

2/28/2002

2/27/2032

2AR-00628

Surface & Coal Lease Agreement

5/20/2002

5/19/2022

2AR-00632

Surface Lease Agreement

8/28/2002

8/27/2022

2AR-00633

Coal Lease Agreement

3/17/2003

3/16/2013

2AR-00635

Coal Lease

10/11/2004

10/10/2034

2AR-00636

Coal Lease

10/11/2004

10/10/2034

2AR-00637

Coal Lease

10/11/2004

10/10/2034

2AR-00641

Surface & Coal Lease Agreement

5/12/2004

5/11/2014

2AR-00643

Coal Lease Agreement

8/25/2004

8/24/2024

2AR-00644

Coal Lease Agreement

8/25/2004

8/24/2024

2AR-00645

Coal Lease Agreement

8/25/2004

8/24/2024

2AR-01948

Surface Lease Agreement

1/13/2012

1/12/2032

2AR-01949

Coal Lease Agreement

12/6/2013

12/5/2033

2AR-01950

Coal Lease Agreement

12/6/2013

12/5/2033

2AR-01951

Coal Lease Agreement

12/17/2013

12/16/2033

2AR-01952

Coal Lease Agreement

12/31/2013

12/30/2033

2AR-01953

Coal Lease Agreement

3/13/2014

3/12/2034

2AR-01955

Coal Lease Agreement

7/8/2016

7/7/2036

2AR-01957

Coal Lease Agreement

8/15/2016

8/14/2026

2AR-01958

Coal Lease Agreement

9/12/2016

9/11/2026

2AR-01959

Coal Lease Agreement

7/28/2016

7/27/2026

2AR-01960

Surface Lease Agreement

7/6/2018

7/5/2043

2AR-01961

Surface Lease Agreement

12/11/2018

12/10/2043

2AR-01962

Coal Lease Agreement

6/14/2020

6/13/2045

2AR-01963

Coal Lease Agreement

6/16/2020

6/15/2045

2AR-01964

Coal Lease Agreement

6/16/2020

6/15/2045

2AR-01965

Coal Lease Agreement

7/2/2020

7/1/2045

2AR-01966

Coal Lease Agreement

7/2/2020

7/1/2045

SEC S-K 1300 Individual Property Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

2AR-01967

Coal Lease Agreement

7/6/2020

7/5/2045

2AR-01968

Coal Lease Agreement

7/7/2020

7/6/2045

2AR-01969

Coal Lease Agreement

7/7/2020

7/6/2045

2AR-01970

Coal Lease Agreement

7/7/2020

7/6/2045

2AR-01971

Coal Lease Agreement

7/8/2020

7/7/2045

2AR-01972

Coal Lease Agreement

7/24/2020

7/23/2045

2AR-01973

Coal Lease Agreement

7/25/2020

7/24/2045

2AR-01974

Coal Lease Agreement

8/10/2020

8/9/2045

2AR-01975

Coal Lease Agreement

8/13/2020

8/12/2045

2AR-01976

Coal Lease Agreement

8/14/2020

8/13/2045

2AR-01977

Coal Lease Agreement

8/17/2020

8/16/2045

2AR-01978

Coal Lease Agreement

8/18/2020

8/17/2045

2AR-01979

Coal Lease Agreement

8/24/2020

8/23/2045

2AR-01980

Coal Lease Agreement

8/25/2020

8/24/2045

2AR-01981

Coal Lease Agreement

8/26/2020

8/25/2045

2AR-01982

Coal Lease Agreement

8/26/2020

8/25/2045

2AR-01983

Coal Lease Agreement

8/27/2020

8/26/2045

2AR-01984

Coal Lease Agreement

9/2/2020

9/1/2045

2AR-01985

Coal Lease Agreement

8/23/2020

8/22/2045

2AR-01986

Coal Lease Agreement

9/2/2020

9/1/2045

2AR-01987

Coal Lease Agreement

9/8/2020

9/7/2045

2AR-01988

Coal Lease Agreement

9/8/2020

9/7/2045

2AR-01989

Coal Lease Agreement

9/3/2020

9/2/2045

2AR-01990

Coal Lease Agreement

9/15/2020

9/14/2045

2AR-01991

Coal Lease Agreement

9/16/2020

9/15/2045

2AR-01992

Coal Lease Agreement

9/15/2020

9/14/2045

2AR-01993

Surface & Coal Lease Agreement

9/16/2020

9/15/2045

2AR-01994

Surface & Coal Lease Agreement

9/15/2020

9/14/2045

2AR-01995

Coal Lease Agreement

9/16/2020

9/15/2045

2AR-01996

Surface & Coal Lease Agreement

9/15/2020

9/14/2045

2AR-01997

Surface & Coal Lease Agreement

9/15/2020

9/14/2045

2AR-01998

Coal Lease Agreement

10/6/2020

10/5/2045

2AR-01999

Coal Lease Agreement

10/6/2020

10/5/2045

2AR-06000

Coal Lease Agreement

10/14/2020

10/13/2045

2AR-06001

Coal Lease Agreement

10/15/2020

10/14/2045

2AR-06002

Coal Lease Agreement

10/16/2020

10/15/2045

2AR-06003

Coal Lease Agreement

11/2/2020

11/1/2045

2AR-06004

Coal Lease Agreement

11/7/2020

11/6/2045

2AR-06005

Coal Lease Agreement

11/18/2020

11/17/2045

2AR-06006

Coal Lease Agreement

12/22/2020

12/21/2045

2AR-06007

Coal Lease Agreement

12/23/2020

12/22/2045

SEC S-K 1300 Individual Property Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

2AR-06008

Coal Lease Agreement

12/28/2020

12/27/2045

2AR-06009

Coal Lease Agreement

12/31/2020

12/30/2045

2AR-06010

Coal Lease Agreement

1/4/2021

1/3/2046

2AR-06011

Coal Lease Agreement

1/11/2021

1/10/2046

2AR-06012

Coal Lease Agreement

1/12/2021

1/11/2046

2AR-06013

Coal Lease Agreement

1/14/2021

1/13/2046

2AR-06014

Coal Lease Agreement

1/15/2021

1/14/2046

2AR-06015

Coal Lease Agreement

1/15/2021

1/14/2046

2AR-06016

Coal Lease Agreement

1/16/2021

1/15/2046

2AR-06017

Coal Lease Agreement

1/19/2021

1/18/2046

2AR-06018

Coal Lease Agreement

1/25/2021

1/24/2046

2AR-06019

Coal Lease Agreement

1/30/2021

1/29/2046

2AR-06020

Coal Lease Agreement

5/12/2021

5/11/2046

2AR-06021

Coal Lease Agreement

7/2/2021

7/1/2046

2AR-06022

Coal Lease Agreement

9/2/2021

9/1/2046

2AR-06023

Surface & Coal Lease Agreement

9/13/2021

9/12/2046

2AR-06024

Coal Lease Agreement

9/28/2021

9/27/2046

2DS-00506

Surface & Coal Lease Agreement

12/28/1990

12/27/2010

2DS-00510

Coal Lease

11/26/1969

11/25/1994

2DS-00512

Coal Lease

5/5/1971

5/4/1996

2DS-00514

Coal Lease

11/27/1972

11/26/1997

2DS-00516

Coal Lease

8/1/1973

7/31/1998

2DS-00517

Coal Lease

8/1/1973

7/31/1998

2DS-00518

Coal Lease

4/9/1974

4/8/2014

2DS-00531

Coal Lease

8/27/1970

8/26/2010

2DS-00532

Coal Lease

8/27/1970

8/26/2010

2DS-00534

Coal Mining Lease

8/27/1973

8/26/1998

2DS-00535

Coal Lease

4/29/1971

4/28/2031

2DS-00536

Coal Lease

8/13/1970

8/12/2010

2DS-00537

Coal Lease

8/13/1970

8/12/2010

2DS-00538

Coal Lease

8/14/1970

8/13/2010

2DS-00539

Coal Lease

9/5/1970

9/4/2010

2DS-00541

Coal Lease

3/27/1974

3/26/2014

2DS-00542

Exploration Contract & Coal Lease

1/14/1974

1/13/2015

2DS-00549

Coal Lease Agreement

9/12/1991

9/11/2011

2DS-00550

Coal Lease Agreement

9/12/1991

9/11/2011

2DS-00551

Coal Lease Agreement

9/12/1991

9/11/2011

2DS-00552

Coal Lease Agreement

9/12/1991

9/11/2011

2DS-00553

Coal Lease

12/19/1991

12/18/2001

2DS-00554

Coal Lease

12/19/1991

12/18/2001

2DS-00555

Coal Lease

12/19/1991

12/18/2001

SEC S-K 1300 Individual Property Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

2DS-00556

Coal Lease

12/19/1991

12/18/2001

2DS-00562

Surface & Coal Lease Agreement

6/22/1993

6/21/2013

2DS-00567

Coal Lease

8/2/1973

8/1/1998

2DS-00571

Surface & Coal Lease Agreement

12/8/1994

12/7/2004

2DS-00572

Exploration Contract & Coal Lease

4/2/1974

4/1/1995

2DS-00573

Coal Lease

5/20/1971

5/19/2021

2DS-00574

Coal Lease

5/25/1971

5/24/2011

2DS-00575

Coal Lease

8/14/1970

8/13/2010

2DS-00576

Exploration Contract & Coal Lease

10/10/1973

10/9/2014

2DS-00577

Exploration Contract & Coal Lease

9/5/1973

9/4/2014

2DS-00580

Exploration Contract & Coal Lease

8/25/1973

8/24/2014

2DS-00581

Exploration Contract & Coal Lease

8/30/1973

8/29/2004

2DS-00583

Coal Lease

6/18/1971

6/17/2021

2DS-00584

Coal Lease

1/29/1973

1/28/1998

2DS-00593

Coal Lease Agreement

6/7/1999

6/6/2019

2DS-00594

Coal Lease Agreement

6/11/1999

6/10/2019

2DS-00595

Coal Lease Agreement

6/22/1999

6/21/2019

2DS-00596

Surface & Coal Lease Agreement

6/21/1999

6/20/2019

2DS-00634

Coal Lease Agreement

3/13/2003

3/12/2013

2DS-00642

Coal Lease

10/11/2004

10/10/2034

2FE-00100

Coal Lease

8/30/2017

8/29/2042

2FE-00101

Coal Lease Agreement

8/30/2017

8/29/2042

2FE-00102

Surface Lease

8/30/2017

8/29/2042

2FE-00103

Surface & Coal Lease Agreement

9/11/2017

9/10/2042

2FE-00104

Surface & Coal Lease Agreement

11/28/2017

11/27/2042

2FE-00105

Surface & Coal Lease Agreement

1/29/2018

1/28/2043

2FE-00106

Surface Lease Agreement

2/22/2018

2/21/2043

2FE-00107

Surface Lease Agreement

3/8/2018

3/7/2043

2FE-00108

Surface & Coal Lease Agreement

4/18/2018

4/17/2043

2FE-00109

Surface & Coal Lease Agreement

4/18/2018

4/17/2043

2FE-00110

Surface Lease Agreement

5/11/2018

5/10/2043

2FE-00111

Surface & Coal Lease Agreement

5/11/2018

5/10/2043

2FE-00112

Surface & Coal Lease Agreement

5/31/2018

5/30/2043

2FE-00113

Surface & Coal Lease Agreement

6/12/2018

6/11/2043

2FE-00114

Surface & Coal Lease Agreement

4/12/2018

4/11/2043

2FE-00115

Surface & Coal Lease Agreement

7/10/2018

7/9/2043

2FE-00116

Surface Lease Agreement

9/9/2018

9/8/2043

2FE-00117

Surface & Coal Lease Agreement

8/15/2018

8/14/2043

2FE-00118

Coal Lease Agreement

8/28/2018

8/27/2043

2FE-00119

Coal Lease Agreement

9/4/2018

9/3/2043

2FE-00120

Surface & Coal Lease Agreement

10/3/2018

10/2/2043

SEC S-K 1300 Individual Property Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

2FE-00121

Surface & Coal Lease Agreement

10/4/2018

10/3/2043

2FE-00122

Surface & Coal Lease Agreement

10/11/2018

10/10/2043

2FE-00123

Coal Lease Agreement

8/15/2018

8/14/2043

2FE-00124

Surface Lease Agreement

11/2/2018

11/1/2043

2FE-00125

Surface & Coal Lease Agreement

11/9/2018

11/8/2043

2FE-00126

Surface & Coal Lease Agreement

11/15/2018

11/14/2043

2FE-00127

Surface & Coal Lease Agreement

11/16/2018

11/15/2043

2FE-00128

Surface & Coal Lease Agreement

12/31/2018

12/30/2043

2FE-00129

Surface & Coal Lease Agreement

3/8/2019

3/7/2044

2FE-00130

Surface & Coal Lease Agreement

3/8/2019

3/7/2044

2FE-00131

Surface & Coal Lease Agreement

8/20/2019

8/19/2044

2FE-00132

Coal Lease Agreement

9/26/2019

9/25/2044

2FE-00133

Surface Lease Agreement

10/18/2019

10/17/2044

2FE-00134

Surface Lease Agreement

10/18/2019

10/17/2044

2FE-00135

Coal Lease Agreement

10/17/2019

10/16/2044

2FE-00136

Surface Lease Agreement

10/18/2019

10/17/2044

2FE-00137

Coal Lease Agreement

10/16/2019

10/15/2044

2FE-00138

Coal Lease Agreement

11/1/2019

10/31/2044

2FE-00139

Coal Lease Agreement

11/4/2019

11/3/2044

2FE-00140

Coal Lease Agreement

11/6/2019

11/5/2044

2FE-00141

Coal Lease Agreement

11/8/2019

11/7/2044

2FE-00142

Coal Lease Agreement

11/6/2019

11/5/2044

2FE-00143

Coal Lease Agreement

11/12/2019

11/11/2044

2FE-00144

Coal Lease Agreement

12/16/2019

12/15/2044

2FE-00145

Coal Lease Agreement

12/24/2019

12/23/2044

2FE-00146

Coal Lease Agreement

12/26/2019

12/25/2044

2FE-00147

Coal Lease Agreement

1/22/2020

1/21/2045

2FE-00148

Coal Lease Agreement

2/18/2020

2/17/2045

2FE-00149

Coal Lease Agreement

2/18/2020

2/17/2045

2FE-00150

Coal Lease Agreement

2/24/2020

2/23/2045

2FE-00151

Coal Lease Agreement

2/25/2020

2/24/2045

2FE-00152

Coal Lease Agreement

3/2/2020

3/1/2045

2FE-00153

Coal Lease Agreement

3/2/2020

3/1/2045

2FE-00154

Coal Lease Agreement

2/18/2020

2/17/2045

2FE-00155

Coal Lease Agreement

3/4/2020

3/3/2045

2FE-00156

Coal Lease Agreement

3/4/2020

3/3/2045

2FE-00157

Coal Lease Agreement

3/13/2020

3/12/2045

2FE-00158

Coal Lease Agreement

3/6/2020

3/5/2045

2FE-00159

Coal Lease Agreement

3/24/2020

3/23/2045

2FE-00160

Coal Lease Agreement

3/31/2020

3/30/2045

2FE-00161

Coal Lease Agreement

4/13/2020

4/12/2045

SEC S-K 1300 Individual Property Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

2FE-00162

Coal Lease Agreement

5/2/2020

5/1/2045

2FE-00163

Coal Lease Agreement

5/14/2021

5/13/2046

2FE-00164

Coal Lease Agreement

9/1/2021

8/31/2046

2PR-00607

Surface & Coal Lease Agreement

12/17/2000

12/16/2020

2PR-00611

Surface & Coal Lease Agreement

4/25/2001

4/24/2021

2PR-00614

Coal Lease Agreement

9/9/2001

9/8/2011

2PR-01105

Coal Lease

8/25/1966

8/24/2016

2PR-01107

Coal Lease

7/25/1966

7/24/2006

2PR-01116

Surface Lease

4/24/1965

4/23/2015

2PR-01117

Coal Lease

4/24/1965

4/23/2015

2PR-01119

Coal Lease

5/12/1966

5/11/2016

2PR-01120

Coal Lease

5/12/1966

5/11/2006

2PR-01121

Coal Lease

4/8/1970

4/7/2010

2PR-01122

Coal Lease

10/23/1963

10/22/2003

2PR-01123

Coal Lease

9/11/1965

9/10/2005

2PR-01127

Coal Lease

5/9/1965

5/8/2015

2PR-01128

Coal Lease

9/15/1964

9/14/2004

2PR-01130

Coal Lease

7/29/1971

7/28/2021

2PR-01136

Coal Lease

5/25/1970

5/24/2020

2PR-01138

Coal Lease

5/24/1962

5/23/2012

2PR-01145

Coal Lease

8/13/1970

8/12/2010

2PR-01148

Coal Lease

9/8/1964

9/7/2014

2PR-01149

Lease

9/8/1965

9/7/2015

2PR-01152

Coal Lease

9/18/1964

9/17/2014

2PR-01154

Coal Lease

6/21/1972

6/20/2022

2PR-01155

Coal Lease

8/22/1970

8/21/2020

2PR-01156

Coal Lease

6/17/1971

6/16/2021

2PR-01160

Coal Lease

4/30/1965

4/29/2015

2PR-01166

Surface Lease

9/22/1964

9/21/2044

2PR-01177

Coal Lease

9/18/1964

9/17/2014

2PR-01178

Lease

9/18/1964

9/17/2014

2PR-01204

Coal Lease

6/18/1971

6/17/2021

2PR-01219

Coal Lease

9/18/1964

9/17/2004

2PR-01224

Surface Lease

3/8/1965

3/7/2015

2PR-01225

Surface Lease

3/8/1965

3/7/2015

2PR-01227

Surface Lease

3/8/1965

3/7/2015

2PT-00318

Exploration Contract & Coal Lease

10/25/1982

10/24/2022

2PT-00319

Coal Lease

10/25/1982

10/24/2012

2PT-00320

Coal Lease

10/25/1982

10/24/2012

2PT-00321

Coal Lease

10/25/1982

10/24/2012

2PT-00322

Coal Lease

10/25/1982

10/24/2012

SEC S-K 1300 Individual Property Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

2PT-00323

Coal Lease

10/25/1982

10/24/2012

2PT-00327

Coal Lease

10/29/1982

10/28/2022

2PT-00328

Coal Lease

10/14/1982

10/13/2022

2PT-00329

Coal Lease

10/14/1982

10/13/2022

2PT-00330

Coal Lease

10/25/1982

10/24/2012

2PT-00331

Coal Lease

10/29/1982

10/28/2022

2PT-00332

Coal Lease

11/15/1982

11/14/2022

2PT-00333

Coal Lease

11/15/1982

11/14/2022

2PT-00335

Coal Lease

12/22/1982

12/21/2022

2PT-00343

Coal Lease

9/27/1983

9/26/2023

2PT-00610

Surface & Coal Lease Agreement

4/19/2001

4/18/2021

2PT-00627

Surface & Coal Lease Agreement

4/11/2002

4/10/2012

2PT-00629

Coal Lease Agreement

5/20/2002

5/19/2022

2PT-00630

Coal Lease Agreement

6/6/2002

6/5/2012

2PT-00631

Surface & Coal Lease Agreement

8/21/2002

8/20/2022

2PT-00646

Surface & Coal Lease Agreement

7/5/2005

7/4/2015

2PT-00648

Surface & Coal Lease Agreement

1/17/2008

1/16/2028

2PT-01113

Exploration Contract & Coal Lease

8/28/1972

8/27/2013

2PT-01143

Exploration Contract & Coal Lease

9/13/1972

9/12/2013

2PT-01196

Coal Lease

11/13/1969

11/12/1994

2PT-01205

Coal Lease

3/6/1974

3/5/2014

2PT-01206

Coal Lease

3/7/1974

3/6/2014

2PT-01208

Coal Lease

3/13/1974

3/12/2014

2PT-01230

Exploration Contract & Coal Lease

4/6/1981

4/5/2001

2PT-01246

Coal Lease

5/28/1971

5/27/2021

2PT-01249

Coal Lease

5/4/1971

5/3/2021

2PT-01258

Coal Lease

5/25/1971

5/24/2011

2PT-01262

Coal Lease

6/24/1971

6/23/2011

2PT-01265

Coal Lease

5/20/1971

5/19/2021

2PT-01272

Exploration Contract & Coal Lease

10/7/1971

10/6/2012

2PT-01288

Coal Lease

4/1/1974

3/31/2014

2PT-01291

Coal Lease

4/1/1974

3/31/2014

2PT-01293

Coal Lease

4/1/1974

3/31/2014

2PT-01295

Coal Lease

4/1/1974

3/31/2014

2PT-01297

Coal Lease

4/2/1974

4/1/2014

2PT-01298

Coal Mining Lease

8/7/1973

8/6/2003

2PT-01302

Coal Lease

4/2/1974

4/1/2014

2PT-01303

Exploration Contract & Coal Lease

8/1/1973

7/31/2014

2PT-01304

Coal Lease

4/2/1974

4/1/2014

2PT-01307

Exploration Contract & Coal Lease

8/24/1973

8/23/2014

2PT-01312

Coal Lease

4/2/1974

4/1/2014

SEC S-K 1300 Individual Property Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

2PT-01313

Coal Mining Lease

8/17/1973

8/16/2003

2PT-01314

Coal Lease

4/2/1974

4/1/2014

2PT-01315

Coal Lease

4/2/1974

4/1/2014

2PT-01318

Coal Lease

4/2/1974

4/1/2014

2PT-01319

Coal Lease

4/2/1974

4/1/2014

2PT-01320

Coal Lease

4/3/1974

4/2/2014

2PT-01331

Coal Lease

4/24/1974

4/23/2014

2PT-01336

Coal Lease

5/13/1974

5/12/2014

2PT-01339

Coal Mining Lease

8/6/1973

8/5/2013

2PT-01344

Coal Lease

6/4/1971

6/3/1996

2PT-01345

Coal Mining Lease

8/27/1973

8/26/1998

2PT-01651

Coal Lease

6/6/1974

6/5/2014

2PT-01652

Exploration Contract & Coal Lease

8/9/1973

8/8/2014

2PT-01660

Coal Mining Lease

8/23/1973

8/22/2013

2PT-01661

Coal Mining Lease

8/23/1973

8/22/2013

2PT-01662

Coal Mining Lease

8/23/1973

8/22/2013

2PT-01663

Exploration Contract & Coal Lease

8/25/1973

8/24/2014

2PT-01667

Coal Mining Lease

8/29/1973

8/28/2013

2PT-01668

Coal Mining Lease

8/23/1973

8/22/2003

2PT-01669

Coal Mining Lease

8/23/1973

8/22/2003

2PT-01671

Coal Mining Lease

8/17/1973

8/16/2003

2PT-01675

Exploration Contract & Coal Lease

8/28/1973

8/27/2014

2PT-01677

Exploration Contract & Coal Lease

8/30/1973

8/29/2004

2PT-01678

Exploration Contract & Coal Lease

8/28/1973

8/27/2014

2PT-01686

Exploration Contract & Coal Lease

8/28/1973

8/27/2014

2PT-01699

Exploration Contract & Coal Lease

8/24/1973

8/23/2014

2PT-01702

Coal Mining Lease

8/17/1973

8/16/2003

2PT-01707

Exploration Contract & Coal Lease

9/5/1973

9/4/2014

2PT-01709

Exploration Contract & Coal Lease

9/5/1973

9/4/2014

2PT-01712

Exploration Contract & Coal Lease

8/29/1973

8/28/2014

2PT-01715

Exploration Contract & Coal Lease

9/4/1973

9/3/2004

2PT-01729

Exploration Contract & Coal Lease

9/14/1973

9/13/1993

2PT-01731

Coal Mining Lease

8/23/1973

8/22/2003

2PT-01740

Exploration Contract & Coal Lease

9/24/1973

9/23/2014

2PT-01743

Exploration Contract & Coal Lease

8/21/1973

8/20/2014

2PT-01747

Exploration Contract & Coal Lease

9/15/1973

9/14/1993

2PT-01755

Exploration Contract & Coal Lease

9/26/1973

9/25/2014

2PT-01757

Exploration Contract & Coal Lease

9/20/1973

9/19/2014

2PT-01758

Exploration Contract & Coal Lease

9/12/1973

9/11/1993

2PT-01759

Exploration Contract & Coal Lease

10/10/1973

10/9/2014

2PT-01763

Exploration Contract & Coal Lease

11/26/1973

11/25/1994

SEC S-K 1300 Individual Property Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

2PT-01769

Lease

8/7/1973

8/6/2023

2PT-01784

Exploration Contract & Coal Lease

9/20/1973

9/19/1993

2PT-01787

Exploration Contract & Coal Lease

10/1/1973

9/30/1994

2PT-01810

Exploration Contract & Coal Lease

9/20/1973

9/19/1993

2PT-01815

Exploration Contract & Coal Lease

2/15/1974

2/14/2015

2PT-01817

Exploration Contract & Coal Lease

3/7/1974

3/6/2015

2PT-01825

Exploration Contract & Coal Lease

4/2/1974

4/1/1995

2PT-01829

Exploration Contract & Coal Lease

3/26/1974

3/25/1995

2PT-01830

Exploration Contract & Coal Lease

3/26/1974

3/25/1995

2PT-01831

Exploration Contract & Coal Lease

3/26/1974

3/25/1994

2PT-01850

Coal Lease

6/24/1974

6/23/1999

2PT-01852

Coal Lease

6/24/1974

6/23/1999

2PT-01880

Exploration Contract & Coal Lease

11/25/1975

11/24/2016

2PT-01881

Exploration Contract & Coal Lease

11/26/1975

11/25/2016

2PT-01882

Exploration Contract & Coal Lease

11/27/1975

11/26/2016

2PT-01883

Exploration Contract & Coal Lease

11/25/1975

11/24/2016

2PT-01893

Exploration Contract & Coal Lease

11/13/1975

11/12/2016

2PT-01906

Exploration Contract & Coal Lease

12/30/1975

12/29/2016

2PT-01910

Exploration Contract & Coal Lease

10/29/1976

10/28/2016

2PT-01915

Coal Lease

11/12/1976

11/11/2016

2PT-01917

Exploration Contract & Coal Lease

1/5/1977

1/4/2017

2PT-01918

Coal Lease

1/4/1977

1/3/2017

2PT-01920

Coal Lease

10/29/1969

10/28/1994

2PT-01921

Coal Lease

10/30/1969

10/29/1994

2PT-01942

Coal Lease

5/29/1974

5/28/2014

2PT-01946

Coal Lease

5/24/1971

5/23/2021

2RC-00721

Lease

8/1/1973

7/31/2013

2RC-00723

Coal Mining Lease

7/30/1973

7/29/2013

2RC-00727

Coal Lease

6/22/1971

6/21/2011

2RC-00769

Coal Lease

6/9/1965

6/8/2005

2RC-00770

Coal Mining Lease

8/7/1973

8/6/1993

2RC-00774

Coal Lease

1/11/1974

1/10/1994

2RC-00776

Coal Lease

1/3/1974

1/2/1994

2RC-00827

Coal Lease

8/7/1964

8/6/2004

2RC-00828

Lease

8/7/1964

8/6/2004

2RO-00851

Coal Lease

7/25/1997

6/30/2017

2RO-00858

Surface & Coal Lease Agreement

12/4/1997

12/3/2007

2RO-00871

Surface & Coal Lease Agreement

4/19/2001

4/18/2011

2RO-00883

Coal Lease

5/9/2002

5/31/2022

SEC S-K 1300 Individual Property Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

Table 1.2 Identification of Acquisitions

Agreement Id

Agreement Type

Agreement Date

Agreement Expiration Date

213-CTS088

Warranty Deed

5/11/2007

12/31/2099

213-CTS092

Warranty Deed

12/9/2002

12/31/2035

214-CTC002

Mineral Deed

3/31/1975

12/31/2035

234-CTS090

Warranty Deed

9/18/2002

12/31/2035

23R-CTC001

Mineral Deed

8/7/1972

12/31/2099

2-CTC009

Limited Mineral Deed

3/5/1993

12/31/2035

2-CTC010

Mineral Deed

3/10/1994

12/31/2035

2-CTC012

Mineral Deed

12/12/1995

12/31/2099

2-CTC021

Coal Deed

11/6/2009

12/31/2999

2-CTS002

Contract for Deed

12/13/1977

12/31/2099

2-CTS003

Contract for Deed

7/31/1980

12/31/2099

2-CTS007

Quit Claim Deed

12/17/1982

12/31/2999

2-CTS012

Warranty Deed

10/30/1984

12/31/2099

2-CTS015

Warranty Deed

12/30/1987

12/31/2099

2-CTS018

Warranty Deed

6/10/1988

12/31/2099

2-CTS022

Warranty Deed

6/2/1989

12/31/2099

2-CTS033

Warranty Deed

5/6/1992

12/31/2035

2-CTS035

Warranty Deed

5/13/1992

12/31/2035

2-CTS036

Warranty Deed

10/27/1992

12/31/2035

2-CTS063

Warranty Deed

8/15/1997

12/31/2035

2-CTS065

Warranty Deed

12/29/1997

12/31/2035

2-CTS066

Warranty Deed

12/29/1997

12/31/2035

2-CTS077

Warranty Deed

2/29/2000

12/31/2035

2-CTS080

Warranty Deed

5/3/2001

12/31/2099

2-CTS081

Quit Claim Deed

6/20/2001

12/31/2099

2-CTS086

Warranty Deed

11/14/2001

12/31/2099

2-CTS094

Warranty Deed

6/15/2004

12/31/2099

2-CTS109

Warranty Deed

5/16/2005

12/31/2035

2-CTS110

Warranty Deed

1/18/2005

12/31/2035

2-CTS112

Warranty Deed

2/28/2005

12/31/2099

2-CTS113

Warranty Deed

6/11/2005

12/31/2035

2-CTS117

Warranty Deed

12/1/2006

12/31/2099

2-CTS119

Warranty Deed

5/1/2007

12/31/2035

2-CTS120

Warranty Deed

8/17/2005

12/31/2035

2-CTS121

Warranty Deed

10/7/2005

12/31/2099

2-CTS124

Warranty Deed

6/16/2006

12/31/2099

2-CTS125

Warranty Deed

10/19/2006

12/31/2035

2-CTS126

Warranty Deed

6/28/2007

12/31/2035

2-CTS127

Warranty Deed

7/24/2009

12/31/2999

SEC S-K 1300 Individual Property Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

2-CTS128

Warranty Deed

6/22/2009

12/31/2999

2-CTS129

Warranty Deed

4/8/2010

12/31/2999

2-CTS130

Warranty Deed

6/10/2010

12/31/2999

2-CTS131

Warranty Deed

6/10/2010

12/31/2999

2-CTS132

Warranty Deed

12/28/2010

12/31/2099

2-CTS134

Warranty Deed

10/2/2012

12/31/2099

2-CTS135

Warranty Deed

7/23/2014

12/31/2099

2-CTS136

Warranty Deed

9/10/2014

12/31/2999

2-CTS137

Warranty Deed

3/11/2015

12/31/2099

2-CTS138

Warranty Deed

7/21/2015

12/31/2099

2-CTS139

Warranty Deed

11/10/2015

12/31/2099

2-CTS140

Warranty Deed

12/21/2016

12/31/2999

2-CTS141

Warranty Deed

5/2/2017

12/31/2099

2-CTS142

Warranty Deed

1/17/2018

12/31/2099

2-CTS143

Warranty Deed

10/5/2018

12/31/2099

2-CTS144

Warranty Deed

10/22/2018

12/31/2099

2-CTS145

Warranty Deed

10/24/2019

12/31/2099

2-CTS146

Warranty Deed

6/11/2021

12/31/2099

2-CTS147

Warranty Deed

12/20/2021

12/31/2099

2D2-CTC019

Bankruptcy Trustee's Deed

6/4/2003

12/31/2035

2D2-CTS060

Warranty Deed

8/4/1997

12/31/2035

2D2-CTS084

Warranty Deed

10/9/2001

12/31/2099

2D2-CTS093

Bankruptcy Trustee's Deed

6/4/2003

12/31/2035

2D-CTC014

Mineral Deed

11/26/1997

12/31/2999

2D-CTC020

Mineral Deed

11/18/2004

11/18/2103

2D-CTS029

Warranty Deed

11/8/1991

12/31/2035

2D-CTS031

Warranty Deed

3/9/1992

12/31/2099

2D-CTS032

Contract for Deed

3/13/1992

12/31/2035

2D-CTS034

Warranty Deed

5/6/1992

12/31/2035

2D-CTS037

Warranty Deed

10/28/1992

12/31/2035

2D-CTS038

Warranty Deed

11/17/1992

12/31/2035

2D-CTS039

Contract for Deed

1/21/1993

12/31/2035

2D-CTS040

Warranty Deed

1/13/1995

12/31/2035

2D-CTS043

Contract for Deed

9/28/1993

12/31/2035

2D-CTS053

Warranty Deed

2/7/1997

12/31/2999

2D-CTS058

Warranty Deed

8/11/1997

12/31/2035

2D-CTS059

Warranty Deed

7/25/1997

12/31/2035

2D-CTS079

Warranty Deed

6/21/2000

12/31/2035

2D-CTS091

Warranty Deed

12/2/2002

12/31/2099

2M1-CTC013

Mineral Deed

3/19/1996

12/31/2035

2M1-CTS123

Warranty Deed

4/7/2006

12/31/2099

SEC S-K 1300 Individual Property Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

2M2-CTC004

Warranty Deed

5/25/1989

12/31/2035

2M2-CTS005

Warranty Deed

9/23/1982

12/31/2035

2M2-CTS006

Contract for Deed

12/22/1982

12/31/2035

2M2-CTS021

Warranty Deed

5/25/1989

12/31/2035

2M2-CTS030

Warranty Deed

1/3/1992

12/31/2035

2M2-CTS041

Warranty Deed

5/4/1993

12/31/2035

2M2-CTS042

Warranty Deed

5/4/1993

12/31/2035

2M2-CTS057

Warranty Deed

8/11/1997

12/31/2035

2M2-CTS061

Warranty Deed

8/18/1997

12/31/2035

2M2-CTS064

Warranty Deed

1/15/1999

12/31/2035

2M2-CTS067

Warranty Deed

3/10/1998

12/31/2035

2M2-CTS085

Warranty Deed

10/10/2001

12/31/2035

2M2-CTS096

Warranty Deed

2/18/2004

12/31/2035

2M2-CTS097

Warranty Deed

2/18/2004

12/31/2035

2M2-CTS098

Warranty Deed

4/20/2004

12/31/2099

2M2-CTS099

Warranty Deed

4/20/2004

12/31/2099

2M2-CTS100

Warranty Deed

4/20/2004

12/31/2099

2M2-CTS101

Warranty Deed

4/20/2004

12/31/2099

2M2-CTS102

Warranty Deed

4/20/2004

12/31/2099

2M2-CTS103

Warranty Deed

4/20/2004

12/31/2099

2M2-CTS104

Warranty Deed

4/20/2004

12/31/2099

2M2-CTS105

Warranty Deed

6/23/2004

12/31/2099

2M2-CTS114

Warranty Deed

7/13/2005

12/31/2035

2M2-CTS115

Warranty Deed

7/13/2005

12/31/2035

2M2-CTS116

Warranty Deed

7/15/2005

12/31/2035

2M2-CTS122

Warranty Deed

1/17/2007

12/31/2035

2M3-CTS024

Warranty Deed

9/11/1990

12/31/2035

2M3-CTS051

Warranty Deed

10/21/1996

12/31/2035

2M3-CTS075

Warranty Deed

9/20/1999

12/31/2035

2M3-CTS087

Warranty Deed

11/21/2001

12/31/2035

2M3-CTS095

Warranty Deed

8/26/2003

12/31/2099

2M3-CTS111

Quit Claim Deed

3/2/2005

3/31/2035

2M4-CTC003

Warranty Deed

12/30/1987

12/31/2035

2M4-CTC005

Warranty Deed

8/17/1989

12/31/2035

2M4-CTC006

Mineral Deed

6/29/1990

12/31/2035

2M4-CTC007

Warranty Deed

11/5/1990

12/31/2035

2M4-CTC008

Warranty Deed

5/23/1991

12/31/2035

2M4-CTS001

Warranty Deed

6/30/1977

12/31/2099

2M4-CTS004

Warranty Deed

9/3/1981

12/31/2035

2M4-CTS008

Warranty Deed

5/2/1983

12/31/2035

2M4-CTS009

Contract for Deed

12/19/1983

12/31/2035

SEC S-K 1300 Individual Property Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

2M4-CTS010

Contract for Deed

5/23/1984

12/31/2035

2M4-CTS011

Warranty Deed

10/30/1984

12/31/2035

2M4-CTS013

Warranty Deed

11/19/1984

12/31/2035

2M4-CTS014

Contract for Deed

2/13/1985

12/31/2035

2M4-CTS016

Warranty Deed

12/30/1987

12/31/2035

2M4-CTS017

Warranty Deed

3/30/1988

12/31/2035

2M4-CTS019

Contract for Deed

6/10/1988

12/31/2035

2M4-CTS023

Warranty Deed

8/17/1989

12/31/2035

2M4-CTS025

Warranty Deed

11/5/1990

12/31/2035

2M4-CTS026

Warranty Deed

5/23/1991

12/31/2099

2M4-CTS027

Warranty Deed

5/23/1991

12/31/2035

2M4-CTS028

Warranty Deed

11/22/1991

12/31/2099

2PC-CTC018

Mineral Deed

2/28/2001

12/31/2099

2R-CTC015

Warranty Deed

7/17/1998

12/31/2035

2R-CTC016

Mineral Deed

11/2/1998

12/31/2035

2R-CTC017

Warranty Deed

12/28/1999

12/31/2999

2R-CTS044

Warranty Deed

10/24/1994

12/31/2035

2R-CTS049

Warranty Deed

6/28/1996

12/31/2035

2R-CTS050

Warranty Deed

8/1/1996

12/31/2099

2R-CTS054

Warranty Deed

4/16/1997

12/31/2035

2R-CTS055

Warranty Deed

4/18/1997

12/31/2035

2R-CTS062

Warranty Deed

8/26/1997

12/31/2035

2R-CTS068

Warranty Deed

5/5/1998

12/31/2035

2R-CTS069

Warranty Deed

7/29/1999

12/31/2035

2R-CTS070

Warranty Deed

12/30/1999

12/31/2099

2R-CTS074

Warranty Deed

1/15/1999

12/31/2035

2R-CTS076

Warranty Deed

12/28/1999

12/31/2999

2R-CTS078

Warranty Deed

1/17/2003

12/31/2035

2R-CTS082

Warranty Deed

7/26/2001

12/31/2099

2R-CTS083

Quit Claim Deed

9/13/2001

12/31/2099

2R-CTS089

Warranty Deed

8/21/2002

12/31/2035

2R-CTS106

Warranty Deed

9/10/2004

12/31/2035

MINE HISTORY, OPERATIONS AND ENCUMBRANCES

The Coteau Properties Company (Coteau), a subsidiary of The North American Coal Corporation (NACoal) is the owner and operator of the Freedom Mine, an active lignite surface mining operation in production status. NACoal is a wholly-owned subsidiary of NACCO Industries (NACCO). The Freedom Mine generally produces between 12.5 million and 13.5 million tons of lignite coal annually. All production from the mine is delivered to Dakota Coal Company (DCC), a wholly owned subsidiary of Basin Electric Power Cooperative (BEPC). DCC then sells the coal to the Dakota Gasification Company’s Great Plains Synfuels Plant (DGC), Antelope Valley Station (AVS) and Leland Olds Station (LOS), all of which are operated by affiliates of BEPC. There have been no previous owners or operators of the Freedom Mine.

SEC S-K 1300 Individual Property Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

NACoal began exploring the area in the 1970’s, more specifically in MA1, MA2, MA3, and MA4, known as the Beulah-Hazen Areas. The first surface mining permit for Coteau was approved in 1981, and initial boxcuts were opened in 1983. In later years due to the need to expand the mine’s capacity, the Renner’s Cove and Dakota Star areas were acquired. The Renner’s Cove area was originally explored by Consolidation Coal Company (CONSOL) beginning in the 1960’s. Coteau purchased the surface and coal leases for the Renner’s Cove Area from CONSOL in 1993. The Dakota Star area was also originally explored by CONSOL beginning in the 1970’s. Basin Cooperative Services (BCS) purchased the surface and coal leases in the Dakota Star Area from CONSOL. BCS continued the exploration of the Dakota Star area. Coteau purchased the Dakota Star Reserves from BCS in 1990.

Fill-in drilling programs are routinely conducted by Coteau for the purpose of refining guidance related to ongoing operations. It is common practice at the Freedom Mine to tighten the drilling density with-in the three to four-year block ahead of active operations to an average drill hole spacing of 660-feet. However, additional exploration may also be scheduled in areas farther out to increase confidence in future mine plan projections.

The geology encountered at the Freedom Mine is stratigraphic in nature with depositional sequences of sands, silts, clays, and lignite. The bedrock is masked by residual soils, slopewash, and/or glacial drift. The vertical repetition of geologic strata facilitated a straightforward setting to establish and study the baseline geological, geochemical, geotechnical, and geohydrological conditions at the Freedom Mine.

The mine office facilities and original equipment fleets at the Freedom Mine were constructed, acquired, or purchased new during the development stage of the mine. The facilities and equipment are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, Coteau evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.

The total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2020 is $81.5 Million.

The Freedom Mine currently has no significant encumbrances to the property. No NOVs have been issued at the Freedom Mine in the past three years. Coteau currently has all permits in place for the Freedom Mine to operate through 2031. Permit expansions required to extend the life of the mine through 2045, which is the current estimated lives of DGC and AVS, will be acquired as needed. The term of the existing LSA terminates in 2027, although the term may be extended for two additional periods of five years, or until 2037, at the option of the Coteau. Hindering any regulatory changes out of Coteau’s control, the Qualified Persons (QPs) does not anticipate hurdles for approval of future renewal applications. The QP bases this opinion on the mine’s history to meet regulatory requirements.

MINERAL RESOURCES AND RESERVES

MINERAL RESOURCES

The Mineral Resources presented in Table 1.3 below have been estimated by applying a series of geologic and physical limits as well as high-level mining and economic constraints. The mining and economic constraints were limited to a level sufficient to support reasonable prospect for future economic extraction of the estimated Mineral Resources. The categorized Mineral Resources are reported in Table 1.3.

The effective date of Mineral Resource estimates is December 31, 2021.

SEC S-K 1300 Individual Property Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022


			Quality
			Calorific Value	Moisture	Ash	Sulfur	Sodium in Ash
Mine	Resource Classification	Tonnage	(Btu/lb)	(wt%)	(wt%)	(wt%)	(wt%)
	Measured	322,310,200	6,779	37.64	7.27	0.89	5.62
Freedom Mine	Indicated	8,188,400	6,776	37.92	7.22	0.90	6.36
	Measured + Indicated	330,498,600	6,778	37.64	7.27	0.89	5.63
	Inferred	15,000	6,463	37.84	9.78	1.02	1.59

Table 1.3. Mineral Resource Estimates

MINERAL RESERVES

The Mineral Reserves presented in Table 1.4 below were determined to be the economically mineable portion of the measured and indicated Mineral Resources after the consideration of modifying factors related to the mining process. Inferred Mineral Resources were not considered for Mineral Reserves.

The effective date of Mineral Reserve estimates is December 31, 2021.


			Quality
			Calorific Value	Moisture	Ash	Sulfur	Sodium in Ash
Mine	Reserve Classification	Tonnage	(Btu/lb)	(wt%)	(wt%)	(wt%)	(wt%)
	Proven	253,946,500	6,779	37.70	7.19	0.89	5.12
Freedom Mine	Probable	3,552,300	6,756	38.29	6.78	0.84	5.40
	Total	257,498,800	6,779	37.71	7.19	0.88	5.12

Table 1.4. Mineral Reserve Estimates

DISCUSSION OF PRIOR RESOURCE AND RESERVE ESTIMATIONS

Previously, reserves for the Freedom Mine were reported under Guide 7. All controlled tonnage that met the general mining parameters were considered for reserves. Mineral Resources were not considered. Furthermore, subcategories of Mineral Resources as measured, indicated, or inferred and Mineral Reserves as proven or probable were not considered. Table 1.5 below summarizes those reported Mineral Reserves at the end of the last two fiscal years.

SEC S-K 1300 Individual Property Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022


Report Date			Total Tons
1-Jan-21			438,033,501
1-Jan-20			432,795,311
^ The difference in allotment of tons to each category from 2020 to 2021 was due to mining, lease activity, and new geologic evaluations.

Table 1.5. Summary of Prior Mineral Reserves


Freedom Mine	Tonnage
Resource Classification	1-Jan-22	1-Jan-21	Percent Change
Measured	322,310,200	N/A	N/A
Indicated	8,188,400	N/A	N/A
Measured + Indicated	330,498,600	N/A	N/A
Inferred	15,000	N/A	N/A

Reserve Classification	1-Jan-22	1-Jan-21	Percent Change
Proven	253,946,500	N/A	N/A
Probable	3,552,300	N/A	N/A
Total	257,498,800	438,033,501	-41%

Table 1.6. Net difference between 2021 and 2022 reported Mineral Resources and Reserves

Explanation of discrepancies. The primary cause for such a large variance between Mineral Resources and Reserves from January 1, 2021 to the current report date is due to a change in methodology in categorization of Mineral Resources and Reserves from an interpretation of Guide 7 regulations to following the guidance of the Subpart S-K 1300 regulations. Tighter interpretations and guidance of the S-K 1300 regulations narrowed the basis of Mineral Resources and furthermore Mineral Reserves such that a Mineral Resource is defined as:

“A concentration or occurrence of material of economic interest in or on the Earth’s crust in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. A Mineral Resource is a reasonable estimate of mineralization, taking into account relevant factors, such as cut-off grade, likely mining dimensions, location, or continuity, that, with the assumed and justifiable technical and economic conditions, is likely to, in whole or in part, become economically extractable. It is not merely an inventory of all mineralization drilled or sampled.”

A Mineral Reserve is defined as:

“The economically mineable part of a measured or indicated Mineral Resource, which includes diluting materials and allowances for losses that may occur when the material is mined or extracted.”

Additional impacts to the variance in reported Mineral Resources and Reserves from the January 1, 2021 report date to the January 1, 2022 report date include:

–Coteau severed 12,584,181 tons in 2021.

–Coteau acquired and terminated leases in 2021.

SEC S-K 1300 Individual Property Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

MATERIAL ASSUMPTIONS FOR MINERAL RESOURCES AND MINERAL RESERVES

Material assumptions and criteria used in the determination of Mineral Resource and Mineral Reserves reported herein are provided within the filed Technical Report Summary (TRS) for The Coteau Properties Company – Freedom Mine dated February 14, 2022.

Section 11.0 of the TRS describes the key assumptions, parameters, and methods used for the estimation of Mineral Resources. A further description of the verified drilling data used to model the lignite deposit for estimation of Mineral Resources is provided in Section 7.2 Drilling Exploration, 8.0 Sample Preparation, Analyses, and Security, and Section 9.0 Data Verification.

Section 12.0 of the TRS describes the key assumptions, parameters, and methods used for the estimation of Mineral Reserves. Modifying factors including dilution parameters and technical information related to the mining process are described in detail under Section 13.0 Mining Methods. Economic factors to support the Mineral Reserve estimates are described in Section 18.0 Capital and Operating Costs and 19.0 Economic Analyses.

SEC S-K 1300 Internal Controls Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

EXPLORATION DRILLING - GENERAL

Independent drilling companies are contracted by The Coteau Properties Company (Coteau) to drill/retrieve coal cores for the Freedom Mine. Coteau personnel oversee the retrieval of core samples, then log and properly bag those samples for analysis by a certified third-party laboratory, Minnesota Valley Testing Laboratories, Inc. (MVTL) located in Bismarck, North Dakota.

For the purpose of this discussion, senior geologist and field geologist refer to qualified representatives of Coteau and/or the North American Coal Corporation (NACoal).

QUALITY CONTROL AND QUALITY ASSURANCE PROGRAMS

SAMPLE PREPARATION

Upon verifying full recovery of the core run, the field geologist succinctly, but thoroughly logs the lignite run. After the field geologist describes the core run, the entire lignite section is double bagged and tagged. Tags include the date, mine identifier, hole ID, seam ID, and “to” and “from” intervals. Double bagging preserves the moisture of the sample, and tagging on the inside bag safeguards the identification of the sample from the field through transportation to the third-party laboratory, MVTL.

The prep room is a temperature-controlled room (AC and Heat) accessible from the sample receiving and storage room. Within the prep room, samples are crushed to 8-mesh using a crusher and are reduced in volume using a riffler. Two different sized crushers and rifflers are available depending on sample size. Compressed air is used to clean the crusher and riffler after each sample to mitigate contamination.

A riffled split of 8-mesh coal is placed on a sample tray and weighed. The weights are sent electronically to LIMS for use in the moisture calculation. The tray is placed in an air dry oven and dried overnight. The temperature of the air dry ovens is monitored and recorded daily. The temperature monitoring devices are verified annually. Another riffled split is sealed in a Ziploc bag and retained. The client is notified prior to disposal of the coal core splits.

CONTROLS

Retained samples. Total core runs are double bagged and tagged following industry standards for quality analyses, thus split samples in the context of a retained sample are not stored at the Freedom Mine. As such, any retained samples, including 8-mesh and 60-mesh, are stored at MVTL, and collected after total core runs have been crushed and mixed. Additionally, it is important to note that lignite tends to be a high moisture coal which oxidizes rapidly and does not have a long shelf life once removed from the ground. If core splits were retained at Freedom Mine, they would not be representative of in-situ coal properties over a relatively short period of time. All of the analyses in the laboratory are performed on the 60-mesh sample or ash prepared from it. The samples are mixed by tumbling prior to each analysis.

SEC S-K 1300 Internal Controls Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

Duplicate samples. During the lab analyses MVTL runs regular control measures. For calorific value, moisture, ash, volatile matter, sulfur, ash fusion, mineral analysis of ash, carbon, hydrogen, nitrogen, mercury, and chlorine analyses, one duplicate sample is ran for every 10 samples, and a certified reference material (CRM) is analyzed at the beginning and end of each run. For sulfur forms analysis, a laboratory control sample (LCS) and one duplicate analysis is analyzed with each batch. For trace metals, a method blank, laboratory control sample (LCS), and matrix spikes are digested with each batch.

Balances. All balances are calibrated and certified annually by a third-party calibration service. Balances are verified daily using certified weights.

Round Robin Programs and Control Training. MVTL participates in round-robin testing programs with other laboratories to ensure result accuracy. MVTL participates in an Interlab Coal Round Robin Program monthly. In 2020, MVTL also participated in a lignite (coal) specific round robin program with NACoal including 8 laboratories that were used by various NACoal mine locations. The round robin consisted of four samples labeled 2001, 2002, 2003, and 2004. Two samples were sourced from the Red Hills Mine and two samples were sourced from another NACoal mine, Coyote Creek Mine, located in North Dakota. The two locations provided a range of samples with variability in moisture, ash, sulfur and sodium. The labs participating in the round robin were provided 8-mesh splits and dried, 60-mesh splits of all 4 samples. The general results are summarized in Figure 1.0. MVTL Laboratories is labeled “Laboratory #5”.

Figure 1.0. NACoal 2020 Round Robin Program Summary. (NACoal, 2020)

CUSTODY

Core samples remain under the supervision of the field geologist until securely stored in the mine warehouse to be shipped to the third-party laboratory, MVTL. The Freedom Mine office and warehouse facilities are secured with user specified fob access and camera surveillance.

SEC S-K 1300 Internal Controls Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

Once a shipment is received by MVTL, the samples are cross referenced with a chain of custody form or other client paperwork and then are logged into the Laboratory Information Management System (LIMS). Each sample is given a unique lab number used for tracking during analysis and throughout the reporting process.

The building is kept secure, and all doors remain locked throughout the day, except the main customer entrance where visitors have to check in and check out. No access is allowed to the laboratory without an escort. During non-operational hours the building is kept locked.

Retained samples can be reran for analysis within 6-months for selective parameters. MVTL verifies with Coteau prior to disposal of splits and retained samples.

QUALITY PRECISION AND ACCURACY

Coal analysis results are reviewed prior to reporting. The review includes identification of outliers and comparison of results with historical information by site, if available. The analyses are re-analyzed as needed.

Once results are received by Coteau, a visual inspection of results by the senior geologist is followed by a review of summary statistics with the quality of the entire drilling database. Ultimately the results are updated in the geologic model and quality grids are inspected for anomalies. At any point if questionable data is traced back to the laboratory report, the senior geologist may request the lab to rerun a retained sample.

The analytical results from the coal cores collected during Coteau’s exploration programs have proven to be consistent with actual as-delivered quality from the active mining operations at the Freedom Mine. This consistency is based on comparison of historical quality projected from the geologic model for the annual operating plans to actual as-delivered quality indicated by the customer’s Dakota Gasification Company Chemistry Lab.

VERIFICATION OF ANALYTICAL PROCEDURES

The QP has visited the third-party laboratory on multiple occasions. The QP has received a tour of the full facility from the main offices through the receiving dock/storage room, prep room, and primary laboratory, along with all analytic procedures. The facility is well maintained, and clean. Further details about the laboratory are discussed in section 8.0 of the Technical Report Summary (TRS) for The Coteau Properties Company – Freedom Mine, dated February 14, 2022.

COMPREHENSIVE RISK INHERENT IN THE ESTIMATION OF MINERAL RESOURCES AND RESERVES

Although Coteau has remained consistent with coal core sampling programs following and documenting procedures that align with coal industry standards, there are still some inherent risks in the estimation of Mineral Resources and Reserves. This risk falls in the uncertainty within the early Consolidation Coal Company (CONSOL) data collected from the 1960’s to the 1980’s. It is understood that the coal cores were sampled and analyzed as total coal runs. However, the exact method in which samples were bagged, shipped, or analyzed are unknown. Coteau acquired the drill hole data and quality results from CONSOL, but with no documentation on survey standards or QA/QC parameters. Coteau has mitigated this risk by twinning older CONSOL coal core holes, and verifying modeled trends as mining, and subsequently drilling programs, progress. Despite this uncertainty, the data collected by CONSOL has remained fairly consistent when compared to fill-in drilling and quality analyzed before and during active mining operations. The reliability of the drilling data obtained from CONSOL was proven in the Renner’s

SEC S-K 1300 Internal Controls Disclosure

The Coteau Properties Company – Freedom Mine February 14, 2022

Cove Area, due the area being successfully mined out by Coteau. The reliability of the data in the Dakota Star Area has proven to be reliable due to the consistency with fill-in drilling, and successful mining in the area. Verification of lignite quality and trends with newer drilling data has increased the confidence in the early data, but does not eliminate the inherent risk from lack of QA/QC parameters in this small percentage of data in the areas that have not been mined.

Representatives of Coteau or NACoal were not involved in the original drilling exploration programs conducted by Consolidation Coal Company (CONSOL) or Basin Cooperative Services (BCS). Coteau obtained the collar surveys, geophysical logs, coal core analyses, and geologist field logs related to each hole from CONSOL and BCS, but was unable to observe the drilling, sampling, or sample preparation for these data. The largest uncertainty lies in the method of the collar survey of the early data drilled from 1964 to 1980. It is unknown to what degree these holes were surveyed. Coteau has mitigated this risk by twinning older CONSOL coal core holes, and verifying modeled trends as mining, and subsequently drilling programs, progress. Despite this uncertainty, the data collected by CONSOL has remained fairly consistent when compared to fill-in drilling and quality analyzed before and during active mining operations. The reliability of the drilling data obtained from CONSOL was proven in the Renner’s Cove Area, due the area being successfully mined out by Coteau. The reliability of the data in the Dakota Star Area has proven to be reliable due to the consistency with fill-in drilling, and successful mining in the area. Verification of lignite quality and trends with newer drilling data has increased the confidence in the early data, but does not eliminate the inherent risk from lack of QA/QC parameters in this small percentage of data in the areas that have not been mined.

During the drilling and sampling procedure, a variety of factors could materially affect the accuracy and reliability of the results. Some examples include improper surveying of the drill hole collar location and elevation, improper and un-level drill rig set up, improper zeroing out of the elogging tool before commencing geophysical logging, not being able to obtain an elog due to collapsing drill hole conditions, not obtaining 90% recovery of the coal seam cored, allowing the coal core to be exposed for too long before bagging causing a false reduction in moisture and increase in BTU value, and improper record keeping. Most of these negative factors can be avoided by utilizing skilled and experienced drilling and elogging contractors, having proper QA/QC procedures to follow during sampling, and proper drill hole data verification.

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C.

Coyote Creek Mine

Zap, North Dakota

Effective Date: December 31, 2021

Report Date: February 14, 2022

Report Prepared by:

Coyote Creek Mining Company, L.L.C.

6502 17th St. SW

Zap, ND 58580

Signed by Qualified Persons:

Tyler Barth, PE

Kendra Braun, PE

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

TABLE OF CONTENTS


TABLE OF CONTENTS			2
LIST OF TABLES AND FIGURES			6
SIGNATURE AND REPORT DATE			7
1.0	EXECUTIVE SUMMARY		10
		PROPERTY DESCRIPTION AND OWNERSHIP	10
		GEOLOGY AND MINERALIZATION	10
		STATUS OF EXPLORATION	11
		DEVELOPMENT AND OPERATIONS	11
		MINERAL RESOURCE ESTIMATE	11
		MINERAL RESERVE ESTIMATE	12
		CAPITAL AND OPERATING COSTS	13
		ECONOMIC ASSESSMENT	13
		PERMITTING REQUIREMENTS	13
		QUALIFIED PERSONS CONCLUSION AND RECOMMENDATIONS	13
2.0	INTRODUCTION		15
3.0	PROPERTY DESCRIPTION		17
	3.1	PROPERTY LOCATION	17
	3.2	PROPERTY AREA OWNERSHIP	17
	3.3	LEASES AND MINERAL RIGHTS	18
4.0	ACCESSIBILITY, CLIMATE, LOCAL RESOURCES, INFRASTRUCTURE, AND PHYSIOGRAPHY		21
	4.1	PHYSIOGRAPHY, TOPOGRAPHY AND VEGETATION	21
	4.2	ACCESSIBILITY	21
	4.3	CLIMATE	21
	4.4	LOCAL RESOURCES AND INFRASTRUCTURE	22
5.0	HISTORY OF THE PROPERTY		23
	5.1	PREVIOUS OPERATIONS	23
	5.2	EXPLORATION AND DEVELOPMENT HISTORY	23
6.0	GEOLOGICAL SETTING, MINERALIZATION AND DEPOSITION		24

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022


	6.1	GEOLOGY	24
	6.2	LOCAL GEOLOGY	27
7.0	EXPLORATION		31
	7.1	EXPLORATION	31
	7.2	DRILLING EXPLORATION	31
		DRILLING TYPE AND EXTENT	31
		GENERAL DRILLING PROCEDURES	32
		DRILLING EXPLORATION PROGRAMS	32
		QUALIFIED PERSON’S OPINION ON DRILLING EXPLORATION	33
		FACTORS THAT CAN AFFECT THE ACCURACY AND RELIABILITY OF THE DRILLING RESULTS	33
	7.3	HYDROGEOLOGIC CHARACTERIZATION	35
		SURFACE WATER	35
		GROUNDWATER	35
	7.4	GEOTECHNICAL STUDIES	38
8.0	SAMPLE PREPARATION, ANALYSES, AND SECURITY		40
	8.1	SAMPLE COLLECTION AND SHIPMENT	40
	8.2	SAMPLE PREPARATION AND ANALYSIS	41
	8.4	QUALIFIED PERSON’S STATEMENT ON THE ADEQUACY OF SAMPLE PREPARATION, SECURITY AND ANALYTICAL PROCEDURES	43
9.0	DATA VERIFICATION		44
	9.1	DATA VERIFICATION OF DRILL HOLE DATA AND GEOLOGIC (MINERAL RESOURCE) MODEL AND MINERAL RESERVES	44
	9.2	LIMITATIONS ON DATA VERIFICATION	45
	9.3	QUALIFIED PERSON’S STATEMENT OF ADEQUACY OF DATA	45
10.0	MINERAL PROCESSING		46
11.0	MINERAL RESOURCE ESTIMATES		47
	11.1	KEY ASSUMPTIONS, PARAMETERS, AND METHODS	47
		HORIZONS	47
		QUALITY PARAMETERS AND DENSITY DETERMINATION	47
		MODELING PROCESS	48

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022


		JUSTIFICATION OF MODELING METHODS	49
		LIMITS AND CONSTRAINTS ON THE MINERAL RESOURCE ESTIMATES	49
		GENERATION OF PIT SHELLS FOR MINERAL RESOURCE ESTIMATES	50
		MINERAL RESOURCE CLASSIFICATION AND UNCERTAINTY	50
	11.2	MINERAL RESOURCE ESTIMATES	51
		BASIS FOR MINERAL RESOURCE ESTIMATE	51
		MINERAL RESOURCE STATEMENT	52
	11.3	CUT-OFF QUALITY, ASSUMED COST AND SALES PRICE	52
	11.4	QUALIFIED PERSONS CLASSIFICATION OF MINERAL RESOURCES	52
	11.5	UNCERTAINTY IN THE MINERAL RESOURCE ESTIMATES	52
		11.6 QUALIFIED PERSONS POTENTIAL INFLUENCES AFFECTING MINERAL RESOURCE ESTIMATES	53
12.0	MINERAL RESERVE ESTIMATES		54
	12.1	KEY ASSUMPTIONS, PARAMETERS, AND METHODS	54
	12.2	MINERAL RESERVE ESTIMATES	57
		BASIS FOR MINERAL RESERVE ESTIMATE	57
	12.3	CUT-OFF QUALITY AND SALES PRICE	57
		12.5 MULTIPLE COMMODITY MINERAL RESERVE	58
		12.6 QUALIFIED PERSON’S OPINION ON RISK FACTORS THAT	58
13.0	MINING METHODS		59
	13.1	ANNUAL AND TOTAL LIGNITE PRODUCTION	59
	13.2	TYPE AND GENERAL MINING METHOD	59
	13.3	RUN OF MINE TONNAGES	61
	13.4	ENGINEERING STUDIES – DESIGN PARAMETERS	62
		PIT DESIGN	62
		SPOIL STABILITY STUDIES	63
	13.5	HAUL ROADS, RAMPS AND DRAGLINE WALKWAYS	65
	13.6	PERSONNEL AND MAJOR EQUIPMENT	66
14.0	PROCESSING AND RECOVERY METHODS		68
15.0	INFRASTRUCTURE		69

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022


16.0	MARKET STUDIES		71
	16.1	MARKETS	71
	16.2	MATERIAL CONTRACTS	71
17.0	ENVIRONMENTAL STUDIES, PERMITTING, AND PLANS, NEGOTIATIONS, OR AGREEMENTS WITH LOCAL INDIVIDUALS OR GROUPS		72
	17.1	ENVIRONMENTAL AND BASELINE STUDIES	72
	17.2	WASTE DISPOSAL, SITE MONITORING, AND WATER MANAGEMENT	72
		WASTE DISPOSAL	72
		SITE MONITORING	72
		WATER MANAGEMENT	73
	17.3	PERMITS	73
	17.4	RECLAMATION BOND REQUIREMENTS	75
	17.5	PLANS, NEGOTIATIONS, OR AGREEMENTS WITH LOCAL INDIVIDUALS OR GROUPS	75
	17.6	MINE CLOSURE PLANS	75
	17.7	QUALIFIED PERSON’S OPINION OF Adequacy OF CURRENT PLANS	75
	17.8	DESCRIPTION OF ANY COMMITMENTS OT ENSURE LOCAL PROCUREMENT AND HIRING	75
18.0	CAPITAL AND OPERATING COSTS		76
	18.1	OPERATING COSTS	76
	18.2	CAPITAL COSTS	77
19.0	ECONOMIC ANALYSIS		78
	19.1	KEY ASSUMPTIONS, PARAMETERS AND METHODS	78
	19.2	ANNUAL CASH FLOWS	78
	19.3	SENSITIVITY ANALYSIS	78
20.0	ADJACENT PROPERTIES		80
21.0	OTHER RELEVANT DATA AND INFORMATION		81
22.0	INTERPRETATIONS AND CONCLUSIONS		82
23.0	RECOMMENDATIONS		83
24.0	ADDITIONAL REFERENCES		84
25.0	RELIANCE ON INFORMATION PROVIDED BY THE REGISTRANT		85

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

LIST OF TABLES AND FIGURES

LIST OF FIGURES

FIGURE 3.1. LOCATION OF THE COYOTE CREEK MINE

FIGURE 6.1. GEOLOGIC AND TOPOGRAPHIC BEDROCK MAP OF NORTH DAKOTA (BLUEMLE, 1983)

FIGURE 6.2. STRATIGRAPHIC COLUMN OF THE COYOTE CREEK MINE

FIGURE 6.3. GEOLOGIC CROSS SECTION F-F’, NACC-1302 PERMIT AREA

FIGURE 7.1. LOCATION OF DRILL HOLES

FIGURE 7.2. GROUND WATER MAP

FIGURE 7.3. LOCATION OF GEOTECHNICAL BORINGS (BARR ENGINEERING, 2015)

FIGURE 8.1. NACOAL 2020 ROUND ROBIN PROGRAM SUMMARY. (NACOAL, 2020)

FIGURE 12.1. LIFE OF MINE MAP

FIGURE 13.1. RANGE DIAGRAM – SINGLE-PASS METHOD WITH CHOPCUT

FIGURE 13.2. RANGE DIAGRAM – EXCAVATOR PREBENCH

FIGURE 13.3. SOIL MODEL OUTPUTS (BARR ENGINEERING, 2015)

FIGURE 13.4. TYPICAL SECTIONS FOR RUNNING SURFACES

FIGURE 15.1 INFRASTRUCTURE MAP

LIST OF TABLES

TABLE 1.1 MINERAL RESOURCE ESTIMATES

TABLE 1.2 MINERAL RESERVE ESTIMATES

TABLE 3.1 IDENTIFICATION OF LEASES

TABLE 8.1 LIST OF ASTM STANDARDS FOR MVTL

TABLE 11.1 STRATIGRAPHIC HORIZONS

TABLE 11.2 QUALITY LIMITS (AS-RECEIVED BASIS)

TABLE 11.3 UNIT COSTS-MINERAL RESOURCE ESTIMATION PARAMETERS

TABLE 11.4 MINERAL RESOURCE CATEGORY DISTANCES

TABLE 11.5 MINERAL RESOURCE ESTIMATES

TABLE 12.1 MINERAL RESERVE ESTIMATES

TABLE 13.1 PROJECTED LIFE OF MINE QUALITY

TABLE 13.2 R-O-M DILUTION PARAMETERS

TABLE 13.3 SPOIL STABILITY RESULTS

TABLE 18.1 COST ASSUMPTIONS

TABLE 18.2 CAPITAL COSTS

TABLE 19.1 COST OF COAL

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

SIGNATURE AND REPORT DATE

The effective date of this Technical Report Summary is December 31, 2021.


QP Name	Sections Responsible For	Signature
Tyler L. Barth	1, 2, 3, 4, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25
Kendra R. Braun	2, 3, 4, 5, 6, 7, 8, 9, 11, 12, 17, 22, 23, 24, 25

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

CERTIFICATE OF QUALIFIED PERSON TYLER L. BARTH

(a)I am the Engineering Manager at Coyote Creek Mining Company’s Coyote Creek Mine in Zap ND; a position I have held since 2017.

(b)This certificate applies to the Technical Report Summary titled, “SEC S-K 1300 Technical Report Summary, Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine, Zap, North Dakota.

(c)I am a Qualified Person (QP) for the purpose of SEC S-K 1300. My qualifications as a qualified person are as follows:

a.I am a graduate of the South Dakota School of Mines and Technology with a Bachelor of Science in Mining Engineering and Management in 2010 and a Masters of Science in Engineering Management in 2013.

b.I am a Professional Engineer of the state of North Dakota (License Number 9798).

c.My relevant experience of over 11 years, for the purpose of the Technical Report Summary, includes operating experience in various technical, operational, and managerial roles, all of which have been in the coal industry.

d.I am currently employed by Coyote Creek Mining Company L.L.C. at the Coyote Creek Mine where I conduct personal inspections of each mining area on a regular basis described in this Technical Report Summary.

e.I am responsible for the sections listed in Table 0.0 of the Technical Report.

f.I have read SEC S-K 1300 Technical Report Summary requirements. The part of the Technical Report Summary for which I am responsible has been prepared in compliance with this requirement.

Dated this 14th day of February, 2022

Tyler L. Barth

Coyote Creek Mining Company L.L.C.

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

CERTIFICATE OF QUALIFIED PERSON KENDRA R. BRAUN

(d)I am a Geological Engineer at The Coteau Properties Company Freedom Mine in Beulah, ND; a position I have held since my hire in 2009.

(e)This certificate applies to the Technical Report Summary titled, “SEC S-K 1300 Technical Report Summary, Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine, Zap, North Dakota.

(f)I am a Qualified Person (QP) for the purpose of SEC S-K 1300. My qualifications as a qualified person are as follows:

a.I am a graduate of South Dakota School of Mines and Technology with a Bachelor of Science in Geological Engineering in 2009.

b.I am a Professional Engineer of the state of North Dakota (License Number PE-9807).

c.My relevant experience of over 12 years, for the purpose of the Technical Report Summary, includes exploration, mine geology and various technical roles in the coal industry.

d.I am currently employed by The Coteau Properties Company at the Freedom Mine. I oversee the drilling explorations programs at the Freedom Mine and the Coyote Creek Mine, and conduct personal inspections of each mining area on a regular basis described in this Technical Report Summary.

e.I am responsible for the sections listed in Table 0.0 of the Technical Report.

f.I have read SEC S-K 1300 Technical Report Summary requirements. The part of the Technical Report Summary for which I am responsible has been prepared in compliance with this requirement.

Dated this 14th day of February, 2022

Kendra R. Braun

The Coteau Properties Company

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

1.0 EXECUTIVE SUMMARY

This Technical Report Summary (TRS) was prepared for Coyote Creek Mining Company, L.L.C. (Coyote) to report Mineral Resources and Mineral Reserves for the Coyote Creek Mine in Mercer County, North Dakota.

PROPERTY DESCRIPTION AND OWNERSHIP

The Coyote Creek Mining Company, L.L.C. (Coyote), a subsidiary of The North American Coal Corporation (NACoal) is the owner and operator of the Coyote Creek Mine, an active lignite surface mining operation in production status. NACoal is a wholly-owned subsidiary of NACCO. All production from the Coyote Creek Mine is delivered to the Coyote Station owned by Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Company (MDU) and Northwestern Corporation (collectively, the Coyote Station Owners) under a long-term lignite sales agreement (LSA) that expires in 2040. There have been no previous operators of the Coyote Creek Mine.

Coyote provides mining services under the LSA. Coyote Station is Coyote’s only customer under an all-requirements cost-plus management fee LSA. Under the LSA, Coyote receives a contractually-agreed fee based on the amount of lignite delivered. While Coyote is responsible for all mine operations, the Coyote Station Owners are responsible for funding all mine operating costs and guarantee all of the capital required to build and operate the mine. This contract structure eliminates exposure to spot coal market price fluctuations.

Coyote Creek Mine holds 86 leases granting the right to mine approximately 8,129 acres of coal interests, and the right to utilize approximately 15,168 acres of surface interests. Coyote owns in fee approximately 160 acres of surface interest, and has four easements on approximately 352 acres.

The Coyote Creek Mine is located approximately nine miles southwest of Beulah, North Dakota (ND), in Mercer County, which is approximately 75 miles northwest of Bismarck, ND.

GEOLOGY AND MINERALIZATION

The Coyote Creek Mine is located in the Sentinel Butte Formation of the Fort Union Group (Figure 6.1) which is one of the most prolific lignite-bearing stratum in the state. The most prominent characteristics of the Fort Union Group formations are the cyclical deposition and lateral persistence of the lithologic units, especially the lignite seams. The regional structural geology is fairly consistent. No evidence of any significant faulting has been observed in the region. The lignite seams are gently undulating due to differential compaction of the underlying sediments.

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

STATUS OF EXPLORATION

Substantial information has been gathered during exploration drilling programs within the region since the 1970s. These data sets were the foundation for the characterization of the substrate composition, geometry, and structure of the Coyote Creek Mine lignite deposit prior to mining.

Data collected for over 760 drill holes during drilling exploration programs at the Coyote Creek Mine from 2012 to present, is the sole information utilized for modeling the lignite deposit for the determination of Mineral Resources and Reserves for the Coyote Creek Mine

DEVELOPMENT AND OPERATIONS

The Coyote Creek Mine is a single seam lignite surface mining operation which supplies approximately 1.7-2.0 million tons of lignite per year to the adjacent Coyote Power Station. Actual production is dictated by customer demand. Initial deliveries began in 2016.

Coyote Creek Mine employs a staff and workforce of approximately 110 employees with slight fluctuations in employment levels for seasonal work.

CCMC uses standard surface mining techniques to extract coal. Suitable plant growth material (SPGM) will generally be removed by tractor-scrapers and/or a front end loader or excavator and truck fleet. The SPGM will either be stockpiled in areas designated for topsoil or subsoil stockpiles, or will be directly respread onto regraded areas.

Overburden removal includes the removal of any material between the SPGM and the mineable coal seam. Overburden removal is accomplished with the use of the front end loader or excavator and truck fleet, dragline, tractor-scrapers, track dozers or other auxiliary equipment. Overburden is spoiled by the dragline using several mining techniques. In most areas where the overburden material is stable and the overburden thickness is below 85 feet, a simple side casting method will be used in conjunction with a track dozer. As the overburden thickness increases or highwall stability requires additional support, front end loader or excavator and truck fleets will prebench ahead of the dragline operation.

Once all overburden has been removed, the coal surface is cleaned with a rubber-tired or track dozer. The coal seam is then ripped with a 10-foot shank mounted on a track dozer. Coal will be loaded by a front-end loader and hauled by trucks. The coal is hauled from the pit to an unprocessed coal storage pile adjacent to the coal processing facility. A rubber-tire dozer feeds coal from the unprocessed coal storage pile to the apron feeder which feeds the primary crusher at the coal processing facility. The overall average quality of the mined lignite seam meets the required power plant quality specifications. Therefore, no mineral processing is performed by CCMC

MINERAL RESOURCE ESTIMATE

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

sufficient to support reasonable prospect for future economic extraction of the estimated Mineral Resources. The potential of economic extraction is justified by the terms of the existing LSA with the Coyote Station Owners through 2040.

The QP based the Mineral Resource estimates for the Coyote Creek Mine on a stratigraphic geologic model generated from the verified drilling exploration data.

Mineral Resources classification distances from point of measurement for each class are as follows: Measured – less than 660 feet, Indicated - from 660 feet to 1,320 feet, and Inferred - greater than 1,320 feet. Results of the Mineral Resource Estimation calculations are shown in Table 1.1

The effective date of Mineral Resource estimates is December, 31, 2021.


			Quality
			Calorific Value	Moisture	Ash	Sulfur	Sodium in Ash
Mine/Area	Resource Classification	Tonnage	(Btu/lb)	(wt%)	(wt%)	(wt%)	(wt%)
	Measured	31,202,000	6,943	36.63	7.25	0.94	7.78
Coyote Creek	Indicated	3,905,900	6,942	36.55	7.39	0.97	7.70
	Measured + Indicated	35,107,900	6,943	36.62	7.26	0.94	7.77
	Inferred	N/A	N/A	N/A	N/A	N/A	N/A

Table 1.1. Mineral Resource Estimates

MINERAL RESERVE ESTIMATE

The Mineral Reserves in this TRS were determined to be the economically mineable portion of the Measured and Indicated Mineral Resources after the consideration of modifying factors related to the mining process which convert Measured Resources to Proven Mineral Reserves and Indicated Resources to Probable Mineral Reserves. Inferred Mineral Resources were not considered for Mineral Reserves. A cut-off grade of $2.27/mmBTU has been applied to the Measured and Indicated Resources to upgrade these resources into Proven and Probable Reserves. Mineral Reserves Estimates have been calculated and are shown in Table 1.1.

The effective date of Mineral Reserve estimates is December, 31, 2021.


			Quality
			Calorific Value	Moisture	Ash	Sulfur	Sodium in Ash
Mine/Area	Reserve Classification	Tonnage	(Btu/lb)	(wt%)	(wt%)	(wt%)	(wt%)
	Proven	31,202,000	6,943	36.63	7.25	0.94	7.78
Coyote Creek	Probable	3,905,900	6,942	36.55	7.39	0.97	7.70
	Total	35,107,900	6,943	36.62	7.26	0.94	7.77

Table 1.1. Mineral Reserve Estimates.

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

CAPITAL AND OPERATING COSTS

Annual production costs were estimated to satisfy the contractual terms of the LSA. All costs were estimated based on the most recent life-of-mine tonnage requirement.

Capital costs to fulfil the remaining term of the LSA are estimated to be $44,999,400, however; as required under the LSA, these expenditures will be reimbursed by the Coyote Station Owners.

The LSA eliminates the Coyote Creek Mine’s exposure to spot coal market price fluctuations. As a result of the cost-plus nature of the all-requirements LSA and the mine-mouth location of Coyote Station, factors such transportation costs, location and quality of competing coal reserves, and the ability to compete in the market are not relevant considerations in determining the economic feasibility and viability of the coal reserves associated with the Coyote Creek Mine.

ECONOMIC ASSESSMENT

The primary assumption with respect to the economic viability of the Coyote Creek Mine is the continued operation of Coyote Station and the resultant required annual deliveries. The analysis of economic viability of the Coyote Creek Mine is supported by the existing all-requirements LSA and the life-of-mine plan associated with that contract. Compensation required under the LSA includes reimbursement of all mine operating costs plus a contractually-agreed fee based on the amount of coal delivered. Coyote Station is located directly next to the Coyote Creek Mine (i.e. a mine-mouth operation) and 100% of the required coal to operate Coyote Station is sourced from the Coyote Creek Mine.

The current delivery requirements included in the LOM plan are based on the most recent projections from the Coyote Station owners in January 2021. As Coyote Station has approved this Life-Of-Mine plan on September 28, 2021, it is assumed all costs are reasonable based on that approval.

PERMITTING REQUIREMENTS

There are no outstanding permits related to the Life of Mine (LOM) plan awaiting regulatory approval. Coyote currently has all permits in place for the Coyote Creek Mine to operate and adhere to a mine plan projected through 2040. The term of the existing LSA expires in 2040. Federal Mine Plan Approval is still required from OSMRE to mine Federal Coal. Absent any regulatory changes out of Coyote’s control, the QPs do not anticipate hurdles for approval of future renewal applications. The QPs base this opinion on the mine’s demonstrated success meeting regulatory requirements. Furthermore, appropriate bonding and closure plans are in place with regulatory entities.

QUALIFIED PERSONS CONCLUSION AND RECOMMENDATIONS

All permits have been acquired for continued operation through 2040. No permitting obstacles are anticipated for the permit renewal cycles.

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

Recommendations:

•Continued drilling to expand mineral resources and shore up mineral reserves.

•Monitor environmental regulatory changes for potential effects.

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

2.0 INTRODUCTION

This technical report was prepared for the Coyote Creek Mining Company, L.L.C. (Coyote).

The purpose for which this technical report summary was prepared is to report Mineral Resources and Mineral Reserves for the Coyote Creek Mine located in Mercer County, North Dakota.

The sources of information and data contained in the technical report or used in its preparations were supplied by Coyote and include data used to produce geologic models, production data, environmental support documents, third-party technical studies, resource and reserve estimates, cost estimates, and economic analyses. A large portion of the technical information is summarized from Surface Mining Permits issued by the North Dakota Public Service Commission (NDPSC). Additional references to specific studies and documents are provided in Section 24.0 of this technical report summary (TRS).

Qualified persons (QPs) are employed by NACoal. As such, inspections are conducted on a regular basis and no individual date of inspection has been identified. Tyler L. Barth is a licensed Professional Engineer who has direct engagement with daily production operations and oversight and management of technical projects as the Engineering Manager, and is directly involved in the development of the LOM finances at the Coyote Creek Mine. Kendra R. Braun is a licensed Professional Engineer, who has direct oversight of the drilling exploration programs, and is directly involved in mine development projects at the Coyote Creek Mine.

This is the first TRS filed with the United States Securities and Exchange Commission (SEC) in accordance with S-K Subpart 1300 regulations therefore no preexisting TRS exists with the SEC. Mineral Resource and Reserve estimations prior to December 31, 2021 were reported in accordance with guidance of Industry Guide 7.

This terms of reference for this TRS include

–US English spelling;

–Imperial units of measurement;

–Lignite qualities are presented in weight percent (wt%) and lignite tonnages are present in short tons (2000 lbs);

–Coordinate System is presented in imperial units using the North American Datum 1983 (NAD83), North Dakota State Plane, South Zone;

–Nominal US Dollars as of 2021.

Key Acronyms and definitions for this TRS include:


AR			As-Received Basis
ASTM			American Society for Testing and Materials
Barr			Barr Engineering
BCY			Bank Cubic Yard
BMPs			Best Management Practices
BTU			British Thermal Units
Century GLS			Century Geophysical Logging Services
COC			Chain of Custody
CONSOL			Consolidation Coal Company
Coyote			Coyote Creek Mining Company, L.L.C
Coyote Station Owners			Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Company and Northwestern Corporation
CRIRSCO			Committee for Mineral Reserves International Reporting Standards
gpm			Gallons per Minute

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022


K			Hydraulic Conductivity
lbs			Pounds
LOM			Life of Mine
LSA			Lignite Sales Agreement
MAF			Moisture Ash Free
MDU			Montana-Dakota Utilities Company
mg/L			Milligrams per Liter
mmBTU			million BTU
msl			Mean Sea Level
Mt			Million Tons
MVTL			Minnesota Valley Testing Laboratories, Inc.
NACCO			NACCO Industries
NACoal			The North American Coal Corporation
ND			North Dakota
NDCC			North Dakota Century Code
NDDEQ			North Dakota Department of Environmental Quality
NDDOT			North Dakota Department of Transportation
NDPDES			North Dakota Pollutant Discharge Elimination System
NDPSC			North Dakota Public Service Commission
NELAP			National Environmental Laboratory Accreditation Program
NOV			Notice of Violation
OSMRE			United States Department of the Interior, Office of Surface Mining Reclamation Enforcement
PFS			Pre-feasibility Study
QA/QC			Quality Assurance/Quality Control
QP(s)			Qualified Person(s)
R-O-M			Run of Mine
R-O-W			Right of Way
SEC			United States Securities and Exchange Commission
S-K 1300			SEC’s Subpart S-K 1300 (17 CFR 229.1300)
SMCRA			Surface Mining Control and Reclamation Act
SPCC			Spill Prevention, Control, and Countermeasures
SPGM			Suitable Plant Growth Material
SWPP			Storm Water Pollution and Prevention
TDS			Total Dissolved Solids
TNI			The NELAC Institute
TRS			Technical Report Summary
TSS			Total Suspended Solids
USCS			Unified Soil Classification System
USGS			United States Geological Survey

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

3.0 PROPERTY DESCRIPTION

3.1 PROPERTY LOCATION

The Coyote Creek Mine is located approximately nine miles southwest of Beulah, North Dakota (ND), in Mercer County, which is approximately 75 miles northwest of Bismarck, ND. The main entrance to the mine will be accessed by traveling south of Beulah on Highway 49 for five miles, then west on County Road 25 for four miles. The general location of the Coyote Creek Mine is shown in Figure 3.1 (Location of Coyote Creek Mine). The Coyote Station Power Plant is adjacent to the Coyote Creek Mine.

Figure 3.1. Location of the Coyote Creek Mine.

3.2 PROPERTY AREA OWNERSHIP

Coyote, a subsidiary of NACoal, is the owner and operator of the Coyote Creek Mine, an active lignite surface mining operation in production status. NACoal is a wholly-owned subsidiary of NACCO Industries. All production from the mine is delivered to the Coyote Station owned by Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Company (MDU) and Northwestern Corporation. There have been no previous operators of the Coyote Creek Mine.

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

3.3 LEASES AND MINERAL RIGHTS

Coyote holds 86 leases granting the right to mine approximately 8,129 acres of coal interests and the right to utilize about 15,168 acres of surface interests. In addition, Coyote owns in fee about 160 acres of surface interests and has four easements on approximately 352 acres. The leases, easements, and deeds are recorded at the Mercer County courthouse and are a matter of public record. Substantially all of the leases were acquired over the past 15 years and have continuation provisions that generally permit the leases to be continued beyond their fixed terms. The leases obligate Coyote to make payments based on the amount of lignite mined from the subject property. Most royalty rates range from $.08 - $.16 per ton of lignite mined and are subject to escalation in accordance with the escalator provision in the lease. Payments may also include surface damage payments and advanced or minimum royalty payments. Production royalties are calculated monthly based on surveys and are generally paid on a quarterly basis, although in certain situations royalties are paid monthly. Table 3.1 Identification of Leases, shows the name or identifying number of each lease, or sublease, the nature and extent of Coyote’s title to, or interest in, the associated property, and expiration date of each lease. While Coyote’s leases include a primary, or fixed, term (as set forth in Table 3.1), they include continuation provisions that allow for their continuation beyond their primary terms so long as operations and/or reclamation activities are continuing.

3.4 SIGNIFICANT ENCUMBRANCES TO THE PROPERTY

The Coyote Creek Mine currently has no significant encumbrances to the property. No Notice of Violations (NOVs) have been issued at the Coyote Creek Mine in the past three years. Permitting requirements are discussed in Section 17.0.

3.5 SIGNIFICANT FACTORS AND RISKS

Coyote has not identified any significant risks that may affect the right or ability to perform work on the property. Each lease and special obligations for each lease are reviewed on an annual basis to ensure there is no lapse in lease continuation or payments. If a lease expires or a payment lapses the landowner may choose not to release this property for mining.

3.6 REGISTRANT ROYALTIES AND INTERESTS

Discussed in Section 3.3.

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

Table 3.1 Identification of Leases

Lease Id

Lease Type

Lease Date

Lease Expiration Date

22-02578

Coal Lease

3/24/2014

3/23/2044

22-02579

Coal Lease

3/24/2014

3/23/2044

22-02580

Coal Lease

3/24/2014

3/23/2044

22-02581

Coal Lease

3/24/2014

3/23/2044

22-02582

Coal Lease

3/24/2014

3/23/2044

22-02583

Coal Lease

3/24/2014

3/23/2044

22-02584

Coal Lease

3/24/2014

3/23/2044

22-02585

Coal Lease

3/24/2014

3/23/2044

22-02586

Coal Lease

3/24/2014

3/23/2044

22-02587

Coal Lease

3/24/2014

3/23/2044

22-02588

Coal Lease

3/24/2014

3/23/2044

22-02589

Coal Lease

3/24/2014

3/23/2044

22-02590

Coal Lease

3/24/2014

3/23/2044

22-02591

Coal Lease

3/24/2014

3/23/2044

22-02592

Coal Lease

3/24/2014

3/23/2044

22-02593

Coal Lease

11/1/2020

10/31/2040

22-02505

Coal Lease Agreement

9/29/2010

9/28/2030

22-02513

Coal Lease Agreement

10/14/2010

10/13/2030

22-02514

Coal Lease Agreement

10/14/2010

10/13/2030

22-02515

Coal Lease Agreement

10/20/2010

10/19/2030

22-02516

Coal Lease Agreement

10/12/2010

10/11/2030

22-02517

Coal Lease Agreement

10/13/2010

10/12/2030

22-02518

Coal Lease Agreement

10/22/2010

10/21/2030

22-02519

Coal Lease Agreement

10/28/2010

10/27/2030

22-02520

Coal Lease Agreement

10/15/2010

10/14/2030

22-02521

Coal Lease Agreement

10/22/2010

10/21/2030

22-02525

Coal Lease Agreement

11/13/2010

11/12/2030

22-02526

Coal Lease Agreement

11/4/2010

11/3/2030

22-02527

Coal Lease Agreement

11/1/2010

10/31/2030

22-02528

Coal Lease Agreement

11/4/2010

11/3/2030

22-02529

Coal Lease Agreement

11/11/2010

11/10/2030

22-02530

Coal Lease Agreement

11/15/2010

11/14/2030

22-02531

Coal Lease Agreement

11/1/2010

10/31/2030

22-02532

Coal Lease Agreement

12/3/2010

12/2/2030

22-02533

Coal Lease Agreement

12/3/2010

12/2/2030

22-02534

Coal Lease Agreement

12/3/2010

12/2/2030

22-02538

Coal Lease Agreement

12/29/2010

12/28/2030

22-02539

Coal Lease Agreement

12/29/2010

12/28/2030

22-02540

Coal Lease Agreement

12/29/2010

12/28/2030

22-02541

Coal Lease Agreement

12/29/2010

12/28/2030

22-02542

Coal Lease Agreement

12/29/2010

12/28/2030

22-02543

Coal Lease Agreement

12/29/2010

12/28/2030

22-02544

Coal Lease Agreement

1/26/2011

1/25/2031

22-02545

Coal Lease Agreement

1/28/2011

1/27/2031

22-02546

Coal Lease Agreement

1/10/2011

1/9/2031

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

22-02547

Coal Lease Agreement

1/1/2011

12/31/2030

22-02548

Coal Lease Agreement

2/15/2011

2/14/2031

22-02549

Coal Lease Agreement

3/3/2011

3/2/2031

22-02550

Coal Lease Agreement

2/28/2011

2/27/2031

22-02552

Coal Lease Agreement

3/15/2011

3/14/2031

22-02554

Coal Lease Agreement

12/3/2010

12/2/2030

22-02560

Coal Lease Agreement

7/25/2011

7/24/2031

22-02563

Coal Lease Agreement

12/20/2011

12/19/2031

22-02564

Coal Lease Agreement

12/16/2011

12/15/2031

22-02565

Coal Lease Agreement

12/16/2011

12/15/2031

22-02566

Coal Lease Agreement

1/11/2012

1/10/2032

22-02567

Coal Lease Agreement

2/28/2012

2/27/2032

22-02568

Coal Lease Agreement

3/29/2012

3/28/2032

22-02569

Coal Lease Agreement

5/15/2012

5/14/2032

22-02570

Coal Lease Agreement

5/24/2012

5/23/2032

22-02571

Coal Lease Agreement

6/19/2012

6/18/2032

22-02572

Coal Lease Agreement

5/21/2012

5/20/2032

22-02573

Coal Lease Agreement

5/10/2012

5/9/2032

22-02574

Coal Lease Agreement

7/30/2013

7/29/2033

22-02575

Coal Lease Agreement

9/17/2013

9/16/2033

22-02576

Coal Lease Agreement

10/7/2013

10/6/2033

22-02577

Coal Lease Agreement

2/10/2014

2/9/2034

22-01466

Exploration Contract & Coal Lease

3/28/1975

3/27/2016

22-01467

Exploration Contract & Coal Lease

3/28/1975

3/27/2016

22-02501

Surface & Coal Lease Agreement

9/3/2010

9/2/2030

22-02508

Surface & Coal Lease Agreement

9/29/2010

9/28/2030

22-02509

Surface & Coal Lease Agreement

9/29/2010

9/28/2030

22-02510

Surface & Coal Lease Agreement

9/29/2010

9/28/2030

22-02511

Surface & Coal Lease Agreement

9/29/2010

9/28/2030

22-02512

Surface & Coal Lease Agreement

10/5/2010

10/4/2030

22-02523

Surface & Coal Lease Agreement

11/5/2010

11/4/2030

22-02537

Surface & Coal Lease Agreement

12/29/2010

12/28/2030

22-02556

Surface & Coal Lease Agreement

5/23/2011

5/22/2031

22-02558

Surface & Coal Lease Agreement

7/25/2011

7/24/2031

22-02559

Surface & Coal Lease Agreement

7/25/2011

7/24/2031

22-02561

Surface & Coal Lease Agreement

7/25/2011

7/24/2031

22-02562

Surface & Coal Lease Agreement

10/27/2011

10/26/2031

22-02503

Surface Lease Agreement

9/10/2010

9/9/2030

22-02522

Surface Lease Agreement

11/8/2010

11/7/2030

22-02535

Surface Lease Agreement

12/10/2010

12/9/2030

22-02557

Surface Lease Agreement

8/5/2011

8/4/2031

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

4.0 ACCESSIBILITY, CLIMATE, LOCAL RESOURCES, INFRASTRUCTURE, AND PHYSIOGRAPHY

4.1 PHYSIOGRAPHY, TOPOGRAPHY AND VEGETATION

The Coyote Creek Mine is located in Mercer County, North Dakota within the glaciated subsection of the Missouri Plateau, part of the Great Plains Physiographic Province. The topography of the reserve area may be described as glacially modified bedrock topography. The mantle of drift generally follows the preexisting topography, modifying it only slightly, although in some areas there is some glacial constructional relief. The general effect of the drift has been to lessen the local relief. The major drainages and their main tributaries are pre-glacial bedrock valleys. The Knife River and Coyote Creek are adjusting their profiles to the Missouri River base level, so they are currently aggrading streams. Relief in the area is due largely to erosion in contrast to the depositional landscape of the Missouri Coteau. Relatively softer siltstone and claystone layers locally have been dissected to produce badland topography, but more commonly, smooth rounded slopes are formed between benches. The maximum relief of the Coyote Creek Mine is approximately 370 feet (msl), with the elevation ranging from 1,828 feet (msl) in the valley of Coyote Creek to nearly 2,198feet (msl) in the Tertiary upland ridge tops.

4.2 ACCESSIBILITY

The main entrance to the mine will be accessed by traveling south of Beulah on Highway 49 for five miles, then west on County Road 25 for four miles. The general location of the Coyote Creek Mine is shown in Figure 3.1 Location of Coyote Creek Mine.

Travel to the Coyote Creek Mine by air is possible using the Bismarck Municipal Airport, Bismarck, ND, approximately 75 miles southeast of the mine. From the airport, the mine is accessed using ground transportation by traveling west approximately 50 miles via Interstate 94, taking exit 110 and traveling north approximately 21 miles on ND Highway 49 to County Road 25, then west for four miles on County Road 25.

Travel to the Coyote Creek Mine by rail is possible using the Amtrak Network, which runs through northern North Dakota mostly along the US Highway 2 corridor, and passes through the larger cities of Williston, Minot, Grand Forks, and Fargo, and smaller cities of Stanley, Rugby, and Devils Lake. From these locations, the mine can be accesses via ground transportation on Interstate 29 or Interstate 94 and various highways. The main highways are US Highway 2, US Highway 83, US Highway 85, US Highway 200, and US Highway 281.

North Dakota’s freight rail service is largely provided by Burlington Northern Santa Fe Railway and Canadian Pacific Railway.

4.3 CLIMATE

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inches. Thunderstorms occur on about 34 days each year, and 26 of these days are in summer. Hail accompanies summer thunderstorms in small scattered areas. Blizzards occur several times each winter. Average seasonal snowfall is 28 inches. On the average, 51 days have at least one inch of snow on the ground, but the number of such days varies greatly from year to year.

In winter, the average temperature is 12 degrees F, and the average daily minimum temperature is one degree. In summer the average temperature is 67 degrees, and the average daily maximum temperature is 82 degrees. The percentage of possible sunshine is 70 in summer and 53 in winter. The average relative humidity in mid-afternoon is about 55 percent. Humidity is higher at night, and the average at dawn is about 80 percent. The prevailing wind is from the west-northwest. Average wind speed is highest in April.

4.4 LOCAL RESOURCES AND INFRASTRUCTURE

The towns of Beulah, Hazen, and Stanton along with other smaller communities are within a 40-mile radius of the Coyote Creek Mine and provide a vast supply of the employment base. Employees also come from some of the major cities of Bismarck, Minot, and Dickinson, all of which are less than 100 miles away from the mine.

The Coyote Creek Mine sources power for mine office facilities and operations from Roughrider Electric Cooperative and MDU, and water for the mine office facilities from the Southwest Water Authority. Fuel for equipment is supplied by multiple local vendors. The Coyote Creek Mine has all supporting infrastructure for mining operations. See Section 15.0 for further detail pertaining to the mine specific infrastructure.

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5.0 HISTORY OF THE PROPERTY

5.1 PREVIOUS OPERATIONS

There were no previous operators of the Coyote Creek Mine.

5.2 EXPLORATION AND DEVELOPMENT HISTORY

Original exploration of the Coyote Creek Mine area was conducted by NACoal beginning in the 1970’s. Consolidation Coal Company (CONSOL) conducted some exploration drilling in the vicinity in 1978. In 2012, NACoal conducted a major drilling program to define the reserves within the proposed Coyote Creek permit area, and have continued drilling programs since. The surface coal mining permit was approved in 2014, and initial boxcuts were opened in 2016.

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Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

6.0 GEOLOGICAL SETTING, MINERALIZATION AND DEPOSITION

6.1 GEOLOGY

REGIONAL GEOLOGY

The Coyote Creek Mine is located within the glaciated subsection of the Missouri Plateau, part of the Great Plains Province. The formations of sedimentary origin were deposited in the Williston Basin, the dominant structural feature of western North Dakota. The center of this essentially symmetrical basin is located near the town of Williston, North Dakota, approximately 100 miles northwest of the mine site. The basin consists of approximately 15,000 feet of sedimentary rock overlying a basement complex of gneisses, schists, and granites. This sequence records a geologic time interval spanning late Precambrian (1 to 2 billion years ago) to Holocene (last 10,000 years).

The structural influence of the Williston Basin is reflected in the dip of the formations underlying the Coyote Creek Mine area. Drill hole data indicates that the Sentinel Butte Formation, the uppermost bedrock unit of the sedimentary series within the Coyote Creek Mine area (Figure 6.1), dips westward toward the center of the Williston Basin at 50 to 75 feet per mile (about ½ to 1 degree). The dip of the bedrock strata increases with depth due to the physical characteristics of the Williston Basin. The subsidence of the Williston Basin began early in the Paleozoic Era (425 to 542 million years ago). Subsidence has not been continuous, nor has sedimentation occurred at a constant rate. These irregularities are evidenced by the presence of several unconformities in the stratigraphic column of North Dakota.

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Figure 6.1. Geologic and Topographic Bedrock Map of North Dakota (Bluemle, 1983)

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6.2 LOCAL GEOLOGY

The most prolific lignite-bearing stratum in the state is the Sentinel Butte Formation of the Fort Union Group. The most prominent characteristics of the Fort Union Group formations are the cyclical deposition and lateral persistence of the lithologic units, especially the lignite seams. The Sentinel Butte Formation is a continental deposit comprising interbedded calcareous clays, sandy clays, and lignite beds, with isolated lenses of fine-grained sands, silts, and rare limestones, ranging in color from light gray to dark brown and black. Except for the limestones and an upper sandstone unit, the sediments are essentially nonindurated. The claystone and sandstones are generally thinly bedded and not jointed. These sediments were deposited mainly in swamps or in the floodplains of very slow, meandering rivers. The Sentinel Butte Formation conformably overlies the Tongue River Formation (also known as the Bullion Creek Formation). The Golden Valley Formation, which is stratigraphically above the Sentinel Butte Formation elsewhere, is present near the permit boundary, but is gone in the permit area due to postdepositional erosion; therefore, the younger glacial deposits of the Coleharbor Group unconformably overlie the Sentinel Butte Formation in the study area. Outcrops of the Sentinel Butte Formation are sporadic; bedrock is largely masked by residual soils, slopewash, and/or glacial drift.

The Sentinel Butte Formation incorporates a varying number of lignite coal beds (Figure 6.2 Stratigraphic Column of the Coyote Creek Mine). The major lignite bed within the mine area is the Upper Beulah bed, the only economical lignite deposit. This lignite horizon has a thickness of generally 10 to 12 feet, except near the edges of the glacial diversion channels, where some of the lignite bed has been removed by erosion. Also, along the glacial diversion channels are areas of soft lignite (Leonardite). Soft lignite is a result of areas of the bed being exposed to oxidizing conditions via erosion caused by glacial meltwaters. The soft or weathered lignite is of very poor quality and not economically recoverable.

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Figure 6.2 Stratigraphic Column of the Coyote Creek Mine

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Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

The major lignite bed within the mine area is the Upper Beulah bed. This lignite horizon has a thickness of generally 10 to 12 feet, except near the edges of the glacial diversion channels, where some of the lignite bed has been removed by erosion. Located above the Upper Beulah bed are several thin beds of lignite (Figure 6.2). These include, in the order that they occur, the Harnisch, Twin Buttes, and Schoolhouse beds. The Harnisch is located in an isolated area in the high elevations in the southernmost part of the permit area and ranges in thickness from 1 foot to 6.5 feet. The Twin Buttes is located in the south and west portions of the permit area in the higher elevations and ranges in thickness from 1 foot to 3.5 feet. The Schoolhouse seam spans a large portion of the permit area and ranges in thickness from 1 foot to 3.5 feet. Interburden between the Harnisch and Twin Buttes ranges from 25 to 65 feet. Interburden between the Twin Buttes and Schoolhouse beds ranges between 15 and 50 feet, and interburden between the Schoolhouse and Beulah ranges from 15 to 60 feet.

Located below the Upper Beulah bed are several other beds of lignite (Figure 6.2). The two splits of the Lower Beulah exist in the permit area. The first split lies an average of 5-25 feet below the Upper Beulah and the second split lies 5-20 feet below the first Lower Beulah split. The major beds, in the order below the Lower Beulah beds that they occur, are the Jim Creek and Antelope Creek beds. These range from 40-50 to 60-75 feet below the Upper Beulah bed. The Jim Creek bed has an average thickness of 3 feet, and lies an average of 40-50 feet below the Upper Beulah bed. The Antelope Creek bed averages 2.5 feet thick, and lies an average of 20-25 feet below the Jim Creek bed. Other thin beds and splits of the two beds, typically less than 2 feet thick, are occasionally found above and below the Jim Creek and Antelope Creek beds. Below the Antelope Creek bed the Kinneman Creek lignite zone can be found. The Kinneman Creek in the area consists of up to four splits with varying thicknesses from 1 to 2.5 feet. Below the Kinneman Creek is the Hagel lignite zone, generally made up of two to three beds, and then below that is the Tavis Creek bed. Below the Tavis Creek bed is generally a long sequence of sands and clays before the next lignite (150-300 feet). The Lower Beulah splits, the Jim Creek, and Antelope Creek seams have all been eroded by glacial meltwater in the glacial diversion trenches and do not exist over the whole permit area. However, according to information gathered, the Kinneman Creek seam and seams below it do exist in the permit area.

Geologic cross section F-F’ from the NACC-1302 permit area is included for reference as Figure 6.3 The cross-section was constructed primarily based on the drill hole geophysical logs supplemented with lithology descriptions from the drill cuttings, as well as the data from the core holes.

Workings of inactive or abandoned surface and underground mines have been identified prior to mining. Since mining began, no unique or especially significant geological features, formations, or paleontological resources have been identified at the Coyote Creek Mine. Additionally, no fatal flaws related to geological conditions have been identified.

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Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

Figure 6.3 Geologic Cross-Section F-F’

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Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

7.0 EXPLORATION

7.1 EXPLORATION

No exploration work other than drilling and associated geophysical logging has been conducted at the Coyote Creek Mine. Geophysical logging is discussed with drilling in Section 7.2.

7.2 DRILLING EXPLORATION

Data collected during drilling exploration programs at the Coyote Creek Mine from 2012 to present, is the sole information utilized for modeling the lignite deposit for the determination of Mineral Resources and Reserves for the Coyote Creek Mine. The sampling method used by the Coyote Creek Mine for modeling quality of the lignite deposit is exclusively core drilling. The Coyote Creek Mine lignite deposit is evaluated on a seam by seam basis. Drilling exploration data including geologic lithologies, qualities, and hole locations have been compiled electronically in Excel files.

DRILLING TYPE AND EXTENT

Drilling exploration programs conducted at the Coyote Creek Mine have comprised of rotary air/mist/mud drilling methods. For the purpose of this discussion, senior geologist and field geologist refer to qualified representatives of Coyote and/or NACoal. Historically, Coyote has contracted independent drilling services and geophysical logging services. Drill holes completed at the Coyote Creek Mine are vertical in orientation and have been broken into four categories which are described below. A drill hole location map for the Coyote Creek Mine is presented in Figure 7.1.

Exploratory drill holes, also referred to as pilot holes, are typically 5-inches (outer hole diameter, od) and terminate at a minimum of 12-feet below the lowest targeted lignite seam as specified by the senior geologist to allow for proper geophysical logging. Cuttings are recovered by the contracted driller on a 5-foot interval and are described by the field or senior geologist. All pilot holes are geophyscially logged by a third-party geophysical logging contractor for natural gamma, density, caliper, and resistivity responses. There are instances where a geophysical log cannot be obtained due to poor, collapsing hole conditions, however, footage information is obtained from the driller and the cuttings descriptions.

Coal core holes to collect samples for quality assessment are advanced next to pilot holes at specified locations in accordance to protocols described below. Core holes are typically 5.6-inches outer diameter (od) to core point, then 4.6-inches (od) during coring, with a respective sample diameter of approximately 3-inches (od). Samples are collected with either a 10-foot or a 15-foot split inner tube core barrel. Coring intervals are determined by the field geologist and reviewed by the senior geologist based on the pilot hole’s geophysical log and cuttings descriptions. 90-percent coal core recovery is required (see Section 8.0 for discussion on sample preparation).

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GENERAL DRILLING PROCEDURES

Details may vary with each exploration program, however general procedures for drilling at Coyote Creek Mine include:

–Identification of land control; acquire drilling permissions for properties not owned or previously leased.

–Obtain proper drilling permits for drilling outside of mine permitted areas; acquire Mercer County Temporary Use Permit, and North Dakota State Exploration Permit.

–Site preparation.

–Rotary air/mist/mud drilling by an independent drilling contractor; typically, cuttings are collected every 5-feet.

–Field geologist logs description of cuttings including depth, texture, general color.

–Independent contractor geophysically logs drill hole for natural gamma, density, caliper, and resistivity.

–Field geologist reviews geophysical log.

–Hole determined complete, and abandoned by independent contractor in accordance with regulatory requirements.

–Survey drill hole collar location.

To continue with a coal core hole:

–Coring intervals are determined by field or senior geologist from pilot hole geophysical log.

–Coal core drilling by an independent drilling contractor.

–Core extracted from barrel by independent drilling contractor and placed in logging tray.

–Field geologist measures the core length, identifies the roof and floor, and does a macroscopic description of the core such as fractures, mineralization, texture, ect. If recovery is less than 90-percent, independent drilling contractor may attempt to retrieve the remaining core from the current hole. If no success, the core run interval will be “re-cored” as an additional core hole.

–Field geologist logs the core including depths, fractures, texture, color, and characteristics of the lignite.

–Field geologist double bags and tags sample.

–Once all intervals are cored, independent contractor geophysically logs drill hole if necessary.

–Field geologist reviews geophysical log.

–Hole determined complete and abandoned by an independent contractor in accordance with state regulatory requirements.

–Survey drill hole collar location.

Additional drilling tasks include:

–Maintaining daily drilling report and record of collected samples.

–Proper storage of lignite core samples in secure location of the warehouse to prepare for shipment to laboratory.

DRILLING EXPLORATION PROGRAMS

Numerous drilling exploration programs have been conducted in the Coyote Creek area. Original exploration of the Coyote Creek Mine area was conducted by NACoal from 1972 through 1983. Consolidation Coal Company (CONSOL) also conducted some exploration drilling in the vicinity in 1978. None of these holes are used to model the Coyote Creek Mine area, however, they were previously utilized for initial studies.

In 2012, NACoal conducted a major drilling program to specifically define the reserves within the Coyote Creek permit area, and have continued drilling programs since then. Coyote’s drill hole database contains 769 drill holes that have been drilled by NACoal and Coyote for the Coyote Creek Mine from 2012 through 2020 (Figure 7.1 Location of Drill Holes). Of those holes 267 were sampled for coal quality assessment. For these drill holes, Mohl

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Drilling, Inc. was the main drilling contractor, Century GLS performed much of the geophysical logging, and Minnesota Valley Testing Laboratories, Inc. performed the quality analyses. The minimum drill hole spacing within the controlled tracts within the permit boundary area of the Coyote Creek Mine is approximately 1,320 feet.

The data collected from drilling campaigns completed from 2012 through present are utilized to build the Coyote Creek Geologic Model, and chiefly influence the Coyote Creek Mine Mineral Resource estimations discussed in Section 11.0. No early exploration data are utilized for the Mineral Resource estimations within the Coyote Creek Mine permit area.

QUALIFIED PERSON’S OPINION ON DRILLING EXPLORATION

The QP served as the senior geologist who has overseen the drilling exploration programs conducted from 2012 to present at the Coyote Creek Mine.

As a whole, Coyote plans exploration activities to attain an average 660-foot drilling density for the three-year projection ahead of active mining operations. Thus, the drilling patterns are drilled such that the hole spacing is progressively tightened as mining progresses. Where mining is planned to be more than 10 years away, the hole spacing might be as much as one quarter mile. Within three years of mining, the drilling pattern is complete, and the interior spacing is one hole per 20 acres (660-foot grid). The geology of the erosion and weathering of the coal is complex at the Coyote Creek Mine, therefore heavy cropline drilling takes place. Final subcrop definition is rows of holes 100 feet apart every 300 feet along the subcrop line. Physical constraints such as stream buffers, occupied dwellings, and rough terrain can affect the final drilling density. This spacing allows operations to optimize seam blending efforts to ship a steady fuel quality to the customer. It should be noted for the purpose of Mineral Resource estimations and Life of Mine (LOM) projections, the QP has determined a moderate to high level of confidence in a minimum drill hole spacing of 1,320-feet. This confidence comes from the continuity of the lignite seams including both lithologic and quality characteristics, as well as the ability to compare modeled seam projections to active and historical mining operations. The Coyote Creek Mine has been a producing mine for over 5 years, and has successfully mined over 11.5 million tons of lignite based on the geologic model built off the drilling data in Coyote’s database. Further justification of the drill hole spacing specific to Mineral Resource Classifications is discussed in Section 11.0.

FACTORS THAT CAN AFFECT THE ACCURACY AND RELIABILITY OF THE DRILLING RESULTS

During the drilling and sampling procedure, a variety of factors could materially affect the accuracy and reliability of the results. Some examples include improper surveying of the drill hole collar location and elevation, improper and un-level drill rig set up, improper zeroing out of the elogging tool before commencing geophysical logging, not being able to obtain an elog due to collapsing drill hole conditions, not obtaining 90% recovery of the coal seam cored, allowing the coal core to be exposed for too long before bagging causing a false reduction in moisture and increase in BTU value, and improper record keeping. Most of these negative factors can be avoided by utilizing skilled and experienced drilling and elogging contractors, having proper QA/QC procedures to follow during sampling, and proper drill hole data verification.

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Figure 7.1 Location of Drill Holes

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7.3 HYDROGEOLOGIC CHARACTERIZATION

SURFACE WATER

Initial background surface water studies were conducted in 2012 through 2013 for Coyote Creek and Brush Creek by the Coyote Creek Mining Company L.L.C.

The U.S. Geological Survey has monitored several sites along streams that drain areas currently permitted by Coyote Creek Mine. Previous data from currently inactive USGS stations, or ongoing data from currently active USGS stations, may be used for evaluating variability in water quality and quantity.

GROUNDWATER

The primary water bearing strata at the Coyote Creek Mine include shallow and small lenses of alluvial sands associated with the mantle of glacial till overlaying the permit area, deeper fluvial sands and gravels in major stream valleys, the lignite beds of the Paleocene Sentinel Butte Formation, and deep sandstone beds associated with the Cretaceous Upper Hell Creek and Fox Hills Formations. The Upper Hell Creek Formation and the Fox Hills Formation are regional aquifers that underlay all of Mercer County with the Fox Hills Formation being a large and reliable water source over the area. Aquifers present as existing or potential water supply sources for domestic and livestock use in the area south of the Knife River include the alluvium-filled pre-glacial and glacial channel of the Knife River valley, the thicker lignite beds, and deeper lowermost Paleocene or Cretaceous sandstones, principally the Fox Hills Formation. All of the lignite beds in the Coyote Creek Permit area generally cannot produce water in quantities suitable for normal beneficial uses in human affairs.

A minimum of two years of baseline ground water data were collected and studied within the Coyote Creek permit area. The baseline data collection included water levels, water qualities (alkalinity, hardness, total dissolved solids (TDS), major cation/anions, and select metals), potentiometric head, flow direction, and hydraulic conductivity calculated from pumping tests or single well response (slug) tests. Also, as part of the permitting process, domestic wells and springs within and surrounding the permit areas are certified to determine the well or spring location, well construction details, source aquifer, water chemistry, and pumping or flow rate.

Approximately 80 pre-mining monitoring wells were installed and utilized to characterize the ground water hydrology in and surrounding the Coyote Creek permit area (Figure 7.2 Ground Water Map).

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Figure 7.2 Ground Water Map

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Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

Single well recovery tests have been performed in the permit and adjacent areas of the Coyote Creek Mine. Hydraulic conductivity (K) is derived when field measurements of aquifer responses to hydrostatic pressure changes in a well bore are evaluated with established analytical solutions. All tests on single wells (commonly termed slug tests) used either one or two gallons of potable tap water to produce an initial displacement of hydraulic head above a measured static water level in the well. The recovering water levels are measured at known times by a Solinst Levelogger pressure transducer suspended several feet below static water level. Use of a solid rod introduced into a well to produce displacement and a recovery response is an alternative to using fluid. It has the added advantage of producing a second test run when the rod, or slug, is removed. The generally low water levels in the Coyote Creek Mine monitoring wells made use of a rod and a suspended pressure transducer impossible in many wells. Additionally, introduction of water and the resulting initial raised water levels allowed for a better intuitive assessment of unsaturated gravel pack in wells where the lignite was just at full saturation. This sensitivity was important in many wells that were partially saturated and the depth relationships of well screen, unit top and static water level were uncertain. Some of the wells at Coyote Creek Mine have static water levels below the well screen, and these wells cannot be meaningfully slug tested.

In general, hydraulic conductivity is quite variable in North Dakota lignites. Values for K often vary as much between wells within a unit as between different units. Certain patterns are evident in the Coyote Creek Mine data. As anticipated, the alluvial silty sands and gravels have high hydraulic conductivities due to their coarse textures, moderate sorting and greater saturated thicknesses. They tend to vary far less than hydraulic conductivities in lignite. Alluvium at three sites in Coyote Creek had hydraulic conductivity (K) values that ranged from 0.47 to 1.17 ft/day. Knife River alluvium at one site had K of 0.45 ft/day.

Measuring well responses with digitally recorded, highly sensitive pressure transducers allows accurate measurement of very rapid and very slow well recoveries that often-escaped capture with manual techniques, thus increasing the range of values.

The hydraulic conductivity of the lignites ranged from 0.001 to 11.93 ft/day.

The wide range of hydraulic conductivity values is indicative of the very nature of the lignite beds in the Sentinel Butte Formation. Sedimentary processes formed the lignite beds. Over time, minor fractures developed along the plane of deposition. The extent and degree of these planar, or bedding, fractures are variable and the nature of this fracturing in the strata affects the hydraulic conductivity.

The dominant cation in all the lignite units is sodium and the dominant anions are bicarbonate and sulfate. Total dissolved solids in all the ground waters of the area range from about 701 mg/l to 3210 mg/l with median values showing a slight increase in the deeper lignites.

CCMC’s Sampling Analysis Plan (SAP) thoroughly outlines the QA/QC protocols and procedures for field collection of groundwater and surface water samples in addition to the QA/QC methods implemented by the analytical laboratory. These QA/QC policies and procedures monitor the validity of the test results. Selected independent laboratories for water quality analyses follow the processes and meet the specifications published by national and international standard organizations including The NELAC Institute (TNI-NELAC) which administers the National Environmental Laboratory Accreditation Program (NELAP).

Procedures for collection of water samples for quality analysis include field measurements for pH and temperature using properly washed and calibrated meters/probes. The independent laboratory provides sterile sampling containers and coolers to ship samples. If metals analysis is required, sterile sampling containers with nitric acid are supplied. Sample preservation is dependent upon the matrix and analytical parameter. Once collected, water samples are immediately placed on ice then shipped or delivered to the independent laboratory under chain of custody in sealed coolers to indicate potential tampering during shipment. Storage temperature is maintained at ≤6°C until the analyses are completed by the lab. Samples are typically shipped same day delivery or overnight the day of collection to ensure samples arrive at the laboratory within required parameter holding times.

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7.4 GEOTECHNICAL STUDIES

Geotechnical soil drilling was carried out prior to opening the mine. This baseline study was completed by Barr Engineering Co. in 2015.

The 2015 study included field investigation activities, laboratory testing and slope stability modeling. Three borings were performed in August 2014. Data was also incorporated from drilling and laboratory testing that was performed in 2013 by Coyote.

Locations of the three geotechnical borings are shown on Figure 7.3.

The typical geotechnical borehole log includes the following geotechnical descriptions and records of the sample collected during investigation:

–Lithology: Descriptions of the lithology (typically glacial till, sands, clays, silts, sandy silts, sandy clays, clayey silts, and clayey sands) are recorded for each stratigraphic interval in conjunction with a soil type in accordance with the Unified Soil Classification System (USCS). The soil types encountered at the boring locations include clayey sands (SC), silty sands (SM), silty and sandy clays (CL), glacial till, and lignite.

–Sample Type and Laboratory Data: The soil boring includes the various samples collected during the geotechnical investigation. Sample collection was done by continuous coring and split-barrel sampling. A geophysical electric log (ELOG) was also conducted on the three boreholes. This collected density, electrical resistivity, borehole diameter (caliper), and natural gamma radiation being emitted from material in the borehole wall. Laboratory testing included moisture content, Atterberg Limits, grain-size distribution with hydrometer, and dry density. Consolidated-undrained triaxial compression tests were performed to estimate shear strength characteristics for spoils, overburden, and lower clay. Unconfined compressive strength tests were also carried out to provide comparison for strength parameters for spoil, overburden, and lower clay.

These studies have been used to incorporate best practices and supporting data for the Coyote Creek Ground Control Plan that is submitted to the Mine Safety and Health Administration (MSHA). Guidance for such things as our digging method, depth of prebench highwalls, thickness of and angle of dragline highwalls, spoil height and even the best road building materials have all been gleaned from the information provided in the aforementioned geotechnical studies.

Further detail concerning pit design and ground control parameters related to geotechnical studies are discussed in Section 13.0 Mining Methods.

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Figure 7.3. Location of Geotechnical Borings (Barr Engineering, 2015).

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8.0 SAMPLE PREPARATION, ANALYSES, AND SECURITY

8.1 SAMPLE COLLECTION AND SHIPMENT

The Coyote Creek Mine lignite deposit is evaluated on a seam by seam basis. As a standard in the coal industry, individual sections of lignite are bagged and sent to the third-party coal testing laboratory. The procedures at the Coyote Creek Mine for current and historical sample collection are summarized below.

Upon verifying full recovery of the core run, the field geologist succinctly, but thoroughly logs the lignite run. A typical log describes:

–“to” and “from” depths of burdens and lignite;

–joints and fractures at specified depths;

–characteristics of burden above and below the lignite core;

–roof and floor of lignite seam (i.e. sharp or gradational);

–presence of pyrite or petrified wood;

–observations of clay or sands imbedded in the lignite core;

–and any other prominent characteristics.

After the field geologist describes the core run, the entire lignite section is double bagged and tagged (on the inside bag). Tags include the date, mine identifier, hole ID, seam ID, and “to” and “from” intervals. Double bagging preserves the moisture of the sample, and tagging on the inside bag safeguards the identification of the sample from the field through transportation to the third-party laboratory. Also, the same information on the tag is also written on the outside of the plastic sample bag. Historically, the Coyote Creek Mine has not photographed coal cores prior to bagging samples.

Lignite cores may be split into multiple samples for the following reasons:

–Prominent roof, floors, or partings within a continuous seam;

–Identification of composition concentrations (i.e. to determine if sulfur trends toward top, middle or bottom of seam).

Total core runs are shipped for analysis, thus split samples in the context of a retained sample are not stored at the Coyote Creek Mine. Lignite tends to be a high moisture coal which oxidizes rapidly and does not have a long shelf life once removed from the ground. If core splits were retained, they would not be representative of in-situ coal properties over time.

After samples are bagged, they are stored in a dry, shaded area, typically the field geologist’s truck, until the geologist returns to the mine office. Core samples are then securely stored at the mine warehouse to be shipped to the third-party laboratory. The Coyote Creek Mine office and warehouse is secured with user specified fob access and camera surveillance.

Prior to shipping the samples, the senior geologist reviews each sample against the field records and the chain-of-custody (COC). The date, mine identifier, hole ID, seam ID, and “to” and “from” intervals are verified. A copy of the COC is emailed to the laboratory manager. Copies of the COC forms for coal cores shipped from 2012 through

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2021 were available for the QP to review. Coal core samples are shipped to the third-party laboratory via insured freight with tracking information.

8.2 SAMPLE PREPARATION AND ANALYSIS

Minimum analyses of coal cores include short proximate (moisture, ash, BTU/lb, sulfur, sodium, calcium), and forms of sulfur. These parameters are the primary quality inputs used to model the Coyote Creek Mine lignite deposit. Additional analyses of coal cores may include full proximate, ultimate, mineral analysis of ash, trace elements, and ash fusion, however, these parameters are not modeled or currently relevant for consideration of Mineral Resource estimations.

Minnesota Valley Testing Laboratories, Inc. (MVTL) in Bismarck, North Dakota is the third-party laboratory the Coyote Creek Mine uses for coal core analyses. MVTL has provided coal quality analysis in accordance with ASTM standards for over 40 years. The ASTM standards that MVTL follows for coal analysis are listed below in Table 8.1.


Specific Tests and/or Properties Measured	Specification, Standard, Method, or Test Technique	Items, Materials or Product Tested	Key Equipment or Technology
Ash in the Analysis Sample	ASTM D7582	Coal	TGA
Calorific Value	ASTM D5865	Coal	Calorimeter
Carbon, Hydrogen, and Nitrogen	ASTM D5373	Coal	Elemental Analyzer
Chlorine	ASTM D6721	Coal	Micro-coulometric Analyzer
Fusibility of Ash	ASTM D1857	Coal	Furnace
Mercury	ASTM D6722	Coal	Direct Combustion Analysis
Mineral Analysis of Ash	ASTM D3682/D5016	Coal	ICP-OES, FIA, Furnace
Oven Dry Moisture	ASTM D7582	Coal	TGA
Air Dry Moisture	ASTM D3302	Coal	Air Dry Ovens
Preparing Samples for Analysis	ASTM D2013	Coal	Crusher / Pulverizer
Sulfur (Total)	ASTM D4239	Coal	Furnace
Sulfur Forms	ASTM D2492	Coal	Gravimetric, AA
Trace Metals	ASTM D6357 Modified	Coal	Microwave Digestion, ICP-MS & ICP-OES
Volatile Matter	ASTM D7582	Coal	TGA

Table 8.1. List of ASTM standards for MVTL.

Sample Receiving and Sample Storage Room

Samples are stored until they are ready to be crushed in the prep room. There is a slight potential for moisture loss during this storage period. Coyote acknowledges this potential and, as such, double bags samples in the field to preserve as much in-situ moisture as possible.

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Prep Room

A riffled split of 8-mesh coal is placed on a sample tray and weighed. The weights are sent electronically to LIMS for use in the moisture calculation. The tray is placed in an air dry oven and dried overnight. The temperature of the air dry ovens is monitored and recorded daily. The temperature monitoring devices are verified annually. Another riffled split is sealed in a Ziploc bag and retained. The client is notified prior to disposal of the coal core splits.

Laboratory Testing

8.3 QUALITY CONTROL PROCEDURES

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Figure 8.1. NACoal 2020 Round Robin Program Summary. (NACoal, 2020)

8.4 QUALIFIED PERSON’S STATEMENT ON THE ADEQUACY OF SAMPLE PREPARATION, SECURITY AND ANALYTICAL PROCEEDURES

The consistency in core collection from one drilling program to the next at the Coyote Creek Mine has been thoroughly documented. Through records review and personal observation of numerous drilling campaigns, it is the QP’s opinion that coal core collection at the Coyote Creek Mine has remained consistent. The process of double bagging and tagging the cores in addition to multiple checkpoints to log samples from field to shipment to the lab further ensures the integrity and security of each sample is maintained.

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9.0 DATA VERIFICATION

9.1 DATA VERIFICATION OF DRILL HOLE DATA AND GEOLOGIC (MINERAL RESOURCE) MODEL AND MINERAL RESERVES

The drilling database for the Coyote Creek Mine was organized into three Excel files related to lithology intervals, collar survey, and quality. The files encompass the geologic modeling inputs including lithology intervals, collar survey, total depth of hole, coordinates, and coal core quality data.

The drilling files were saved on the Coyote network drive which contains the geologic model and has limited access.

- Verified each hole has a unique collar location.

- Verified the total hole depth on the collar table matches the total depth on the lithology table.

- Verified the from and to depths on the lithology table and quality table increase down hole.

- Verified for overlapping intervals in the lithology table based on from and to depths.

- Verified the from and to depths on the quality table match the associated seam depths on the lithology table.

For any errors or omissions reported, the QP reviewed the geophysical logs, field logs, and quality reports related to the specified holes to reconcile the differences.

It is the QP’s opinion that the analytical results from the coal cores collected during Coyote’s exploration programs are consistent with actual as-delivered quality from the active mining operations at the Coyote Creek Mine. This opinion was based on comparison of historical quality projected from the Carlson model for the annual operating plans to actual as-delivered quality indicated by the customer’s samples with analysis computed at MVTL. It is also the QP’s opinion that the modeled structure of the lignite seams is consistent with active mining operations based on comparisons of modeled seam thickness and trends against actual surveyed seam thicknesses and trends.

The QP found the geologic model was a reasonable and reliable representation of the geologic structure and quality of the lignite seams (horizons) at the Coyote Creek Mine.

Past and ongoing environmental studies, including ground water and surface water studies, discussed in Sections 7.0 and 17.0 have been reviewed and it is the QP’s opinion they are thorough, complete, and provide the necessary information for the start-up and ongoing operation of the Coyote Creek Mine. The geotechnical studies discussed in Sections 7.0 and 13.0 have been reviewed and it is the opinion of the QP that the geotechnical data is adequate to support the pit angles used by the Coyote Creek Mine. Proper monitoring programs to meet mine permit requirements are in place.

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The QP reviewed the cut-off grade and dilution assumptions and found them to be reasonable and consistent with realized results from the active mining operation. Ash and calorific value (BTU/lb) reject specifications from the LSA are the basis for development of the cut-off grades and it is the QP’s opinion the cut-off grades have been properly established. Recovery rates are constantly being compared to actual recoveries for verification.

The QP has reviewed annual historical values for all costs to be reasonable for future projections, which are refined and updated using the historical values, to continuously improve accuracy of the projections. These have been used to support parameters used during mine planning. The QP considers that reconciliations of staffing and workforce requirements, actual equipment capacities and productivities have been appropriately considered while establishing reliable projections of executing the mine plan.

The Mineral Resource model and other data provided as modifying factors, including those of 3rd party firms, were confirmed as adequate for use in Mineral Reserve Estimation for this TRS.

9.2 LIMITATIONS ON DATA VERIFICATION

The QP does not recognize any uncertainty in the data or any limitations in data verification. The QP has served as the senior geologist and has overseen all drilling programs related to the Coyote Creek Mine, which began in 2012 and continue through present, and has verified all data collected for Coyote.

It is the opinion of the QP that there are no limitations to data verification for Mineral Reserves.

9.3 QUALIFIED PERSON’S STATEMENT OF ADEQUACY OF DATA

Data disclosed in this TRS used for the preparation of geologic models for the purpose of Mineral Resource estimations at the Coyote Creek Mine have been verified by the QP. The QP has served as the senior geologist and has overseen the collection of these data during all drilling exploration programs related to the Coyote Creek Mine, which began in 2012 and continue through present. These data include drill hole surveys, geophysical logs, coal core quality, and other relevant test data.

The QP has verified the data disclosed, including prior technical studies used in the development of the modifying factors, cut-off grade, geotechnical studies, ultimate pit configuration, mine design, schedule, workforce and staff requirements, equipment needs, environmental factors including ground water and surface water studies, and cost assumptions is sufficient for the determination of Mineral Reserves at the Coyote Creek Mine.

It is the QP’s opinion that the data provided for this TRS is more than sufficient for the determination of Mineral Resources and Reserves at the Coyote Creek Mine.

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10.0 MINERAL PROCESSING

Mineral processing does not occur at the Coyote Creek Mine.

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11.0 MINERAL RESOURCE ESTIMATES

11.1 KEY ASSUMPTIONS, PARAMETERS, AND METHODS

The QP developed the stratigraphic geologic model for Mineral Resource estimation using Carlson Mining software. All verified drilling data through 2020 was included in the model. The Coyote Creek Mine lignite deposit was modeled using U.S. customary units projected to NAD 1983 North Dakota State Plane, South Zone coordinate system. Key assumptions, parameters and methods to estimate Mineral Resources are discussed herein.

HORIZONS

The structure of the Coyote Creek Mine deposit is determined by “to” and “from” depth intervals from geophysical logs and geologist’s field logs correlated the drill hole collar survey. Depth picks represent the roof or floor of a lignite seam which define a horizon or domain.

Roofs, floors and partings that meet a minable quality are identified as part of the associated seam, and are modeled in the same manner as the split samples described previously. Roofs, floors and partings that do not meet a minable quality are included in the geologic database as a point of record, but are not modeled with a seam identifier, and thus the quality of those splits is not weighted with the associated seam.

Table 11.1 presents the Stratigraphic Horizons modeled for Mineral Resource estimation. Modeled horizons were required to have quality data in the drilling database to be considered.


HORIZON ID			SEAM NAME
UBEU			Upper Beulah

Table 11.1. Stratigraphic Horizons

QUALITY PARAMETERS AND DENSITY DETERMINATION

The quality parameters modeled for determination of Mineral Resources include calorific value (Btu/lb), moisture (wt%), ash (wt%), sulfur (wt%), and sodium in ash (wt%); typical Short Proximate analysis reported on an as-received (AR) basis. Five quality grids of the above parameters are modeled for each horizon. Generally, the only quality constraint on the mineability of the lignite at the Coyote Creek Mine is weathering/oxidation, which causes a substantial decrease in the heat content of the coal. The lignite existence lines consider the weathering limits of the coal. The low BTU coal is removed from the mineable limits and is not considered as a mineral resource or reserve, therefore there are no quality constraints within the mineable limits of the coal field that can’t be mitigated by blending during mining to meet the customer needs. The minimum and maximum as delivered quality constraints defined in the LSA and are listed under Limits and Constraints below.

NACoal was actively exploring and developing various coal fields in North Dakota, beginning in the early 1970s. The United States Geological Survey and the United States Bureau of Mines had established the average specific gravity (density) of lignite to be 1,750 tons per acre-foot. This density was applied to all the reserve calculations being made by NACoal.

During the late 1970s and early 1980s, coal production started at the Falkirk Mine and the Freedom Mine, which are both mines operated under subsidiaries of NACoal, located in North Dakota. A number of density studies were undertaken at the mines to confirm the validity of the density value being used. It was found that the ASTM specific

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gravity tests on coal cores and other coal samples produced results that were highly variable and difficult to composite into a single seam value. Variations in the organic composition and ash content were believed to be a major cause for the density variations. However, it was also found that when lignite dries, the coal’s structure collapses resulting in a higher density. This density increase from moisture loss is variable and cannot be prevented. For this reason, laboratory measured specific gravities on lignite were not used to calculated resources or reserves.

On several occasions at both the Freedom and Falkirk Mines, density confirmation tests were conducted. For these tests, a relatively small area of a pit was defined and the coal was carefully loaded into trucks for weighing. Then detailed surveys determined the volume of coal removed. These volume and weight tests typically involved over 100 tons of coal and confirmed the 1,750 value; with some expected variability.

In addition, the mines were producing and delivering millions of tons of coal per year. Again, comparison of actual delivered tons versus predicted tons showed very good comparison.

The coal seams mined at the Falkirk Mine, Freedom Mine, and Coyote Creek Mine are all Fort Union lignites. Coyote is mining the same lignite seam as the Freedom Mine. Therefore, Coyote has utilized the same density determined by the previous studies and it has proven to be accurate and comparable to actual delivered tons versus predicted tons.

MODELING PROCESS

The Coyote model consists of all of the drilling data over the whole Coyote Creek Mine permit area. This model is built with 100-foot grid cells.

A surface topography grid is created from a compilation of pre-mining topography contours. The surface grid is created by triangulation at a 100-foot grid cell size for the model.

The lithology and location tables were then referenced by the modeling program and the structural model was developed. The lignite horizons were correlated and modeled using 100-foot grid cells. The thickness structure grids are limited by lignite existence lines, which are the coal croplines that are tagged for the cutoff boundary for each seam. A combination of drill hole data and grid interpolations are used to draw croplines that define the lignite existence and weathering limits. During the modelling process, lithologic data were extrapolated from a maximum of 20 surrounding drill holes using an inverse distance squared calculation to infill the grids where appropriate. The structural model was validated based on geological cross sections and isopach maps of the seam roofs and floors that were created and checked by the QP. Any errors identified in the lithologic descriptions were reconciled.

Lignite quality was then modeled for the entire deposit. As described above, quality data was first composited for each lignite seam by drill hole. As with the structural model, the quality model uses 100-foot grid cells to model quality of the deposit. Drill holes missing quality data employed an inverse distance squared calculation to assign averaged values from a maximum of 20 surrounding drill holes.

Generally, the only quality constraint on the mineability of the lignite at the Coyote Creek Mine is weathering/oxidation, which causes a substantial decrease in the heat content of the coal. The lignite existence lines consider the weathering limits of the coal.

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JUSTIFICATION OF MODELING METHODS

The geologic model at the Coyote Creek Mine is generated using inverse distance methods. This model was established and used in the development of detailed mine plans, financial projections, landowner tonnage estimates, and daily operation plans. The model has proven to be consistent with field conditions (structure and quality), which is likely attributed to the simplistic geology of the region as described in Section 6.0. Geologic units are laterally continuous with generally graded quality. Use of inverse distance methods has proven to be robust in continuous stratigraphic deposits.

The QP did not see a need for Coyote to alter geologic modeling methods.

LIMITS AND CONSTRAINTS ON THE MINERAL RESOURCE ESTIMATES

The Mineral Resources presented in Table 11.4 were estimated by applying a series of geologic and physical limits in addition mining and economic constraints which meet the level of detail required for an initial assessment (IA). Key constraints used by the QP to determine Mineral Resource estimates are summarized below. Details pertaining to physical constraints are discussed further within sections 3.0 and 17.0 of this TRS. Mining and economic constraints specific to Mineral Resource estimates are discussed herein.

Geologic Constraints:

–Modeled roof and floors of each lignite seam (horizon).

–Lignite Existence Lines-Croplines

Physical Constraints:

–Surface topography.

–Lease and fee coal boundaries.

–Surveys of mined out areas

–Offsets from unleased land tracts and occupied dwellings.

–Existing roads and highways, major utilities, and major surface infrastructure without prior agreements for relocation or temporary closure.

Mining and Economic Constraints:

–Resource categorization parameters based on distance from point of observation and drill hole sample count criteria.

–Resource pit shells developed from general mine design parameters and reasonable unit costs used to determine the max cumulative strip ratio for the tonnage to be economical.

–Limits on quality parameters presented in Table 11.2. Quality limits are specified by the LSA.


Parameter	Minimum	Maximum
Calorific Value, Btu/lb	6,500	N/A
Moisture, %wt	N/A	40
Ash, %wt	4	13
Sulfur, %wt	N/A	1.3
Sodium (in ash), %wt	N/A	8

Table 11.2. Quality Limits (as-received basis).

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GENERATION OF PIT SHELLS FOR MINERAL RESOURCE ESTIMATES

Resource pit shells were projected to meet the requirements of the existing LSA to provide lignite fuel to the Coyote Station Power Plant through 2040.

Basic unit costs presented in Table 11.3 were used to determine the maximum reasonable effective stripping ratio of 11:1 for the Coyote Creek Mine deposit assuming an average lignite sales price of $2.27 per mmBTU. The sales price has historically remained fairly steady due to the stripping ratio being fairly consistent. Unit costs were derived from general historic unit costs at the Coyote Creek Mine.


Parameter	Unit	Cost
Burden Removal *	$/BCY	1.00
Royalty	$/ton	0.20

*Burden Removal unit cost was determined assuming the truck-shovel fleet, dozer fleet, and dragline each move 1/3 of the cumulative burden. Fleet unit costs are respectively assumed to be $1.50, $0.75, $0.75 per ton.

Table 11.3. Unit Costs – Mineral Resource estimation parameters.

The QP projected 140-foot pits for each preliminary pit shell in the Carlson mining software. Lignite tonnages and burden volumes for each block were calculated in Carlson mining software then exported to Excel to generate volume and tonnage reports. To optimize the pit shell extents, cumulative strip ratios and cumulative mining costs for each exported block was calculated in MS Excel then visually modeled in a conditionally formatted table. Boundary adjustments were made to the preliminary pit shells accordingly and re-projected. Several mine plan iterations may be performed to optimize mining in the most cost-effective way.

MINERAL RESOURCE CLASSIFICATIONAND UNCERTAINTY

Table 11.1 identified the lignite seams for initial consideration of a Mineral Resource by the QP. The listed seams had a minimum of ten coal core samples for quality estimation, and an average coal core sample quality which fell within the limits provided in Table 11.2. Mineral Resources were then further defined by the identified resource pit shells.

As discussed in Section 7.2 all drill holes within the Coyote Creek Mine deposit obtained structural data related to the lignite seams, where a portion of these drill holes also included quality data from the collection of coal core samples. As such, the QP determined it appropriate that limits for spatial distribution between Mineral Resource categories were based on the average cartesian distances between drill holes that contained quality data. Defining the drill hole distances by the drill holes containing quality data ensured an appropriate density of the quality data was included in each Mineral Resource category. Additionally, due to the methodology of the fill-in drilling at the Coyote Creek Mine, a greater density of quality data would naturally encompass a greater density of structural data.

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Due to the uniformity of the structure and quality of the Coyote Creek coal field, drill hole distances that will define the spatial distribution between Mineral Resource Categories are based on the drill hole distances currently utilized by Coyote As stated in Section 7.2, the minimum drill hole spacing within the controlled tracts within the permit boundary area at the Coyote Creek Mine is 1,320 feet, and fill in drilling tightens the spacing to 660 feet. This drilling density has reliably predicted coal tonnage and quality for over 5 years.

The defined distance limits of the Mineral Resource categories are presented in Table 11.4.


Mineral Resource Category	Lower Distance (Ft)	Upper Distance (Ft)
Measured	0	660
Indicated	660	1,320
Inferred	1,320	5,280

Table 11.4. Mineral Resource category distances.

Measured Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the average distance between quality drill holes is less than or equal to 660 feet. Much of the structural data has been tightened to a density of 660-feet. All of this drilling data was collected by Coyote using known sampling methods and surveying methods. Due to the level of control and oversight during collection of this drilling data, the resulting resource estimates have a high level of confidence by the QP and a low level of uncertainty.

Indicated Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the average distance between quality drill holes is greater than 660 feet and less than or equal to 1,320 feet. Due to the level of control and oversight during collection of this drilling data, the resulting resource estimates have a high level of confidence by the QP and a low level of uncertainty.

Inferred Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the average distance between quality drill holes is greater the 1,320 feet. Modeled values at these distances require a large amount of interpolation between drill holes, however due to the level uniformity of the structure and quality data of the Coyote Creek coal field along with the high level of control and oversight during collection of nearby drilling data, the resulting resource estimates have a moderate to high level of confidence by the QP and a low level of uncertainty.

11.2 MINERAL RESOURCE ESTIMATES

BASIS FOR MINERAL RESOURCE ESTIMATE

The basis of the Mineral Resource estimates for the Coyote Creek Mine deposit and the methods in which they were prepared are summarized for this item. The S-K 1300 regulations (17 CFR 229.1300) define a Mineral Resource as:

Following definitions presented in 17 CFR 229.1300 and guidance from the Committee for Mineral Reserves International Reporting Standards (CRIRSCO), Mineral Resources are divided into three categories as listed below and are ranked by increasing level of confidence. Mineral Resources are reported as in-situ tons such that no adjustments have been made to account for mining recovery or losses.

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geological and quality continuity. Inferred Mineral Resources have the lowest level of confidence determined by the QP.

The QP based the Mineral Resource estimates presented in Table 11.5 for the Coyote Creek Mine on a stratigraphic geologic model generated from the verified drilling exploration data presented in Section 7.0 of this TRS. The choice of stratigraphic modeling is due to the continuous spatial continuity of the lignite seams.

MINERAL RESOURCE STATEMENT

The categorized Mineral Resources are reported herein. The effective date of Mineral Resource estimates is December, 31, 2021.


			Quality
			Calorific Value	Moisture	Ash	Sulfur	Sodium in Ash
Mine/Area	Resource Classification	Tonnage	(Btu/lb)	(wt%)	(wt%)	(wt%)	(wt%)
	Measured	31,202,000	6,943	36.63	7.25	0.94	7.78
Coyote Creek	Indicated	3,905,900	6,942	36.55	7.39	0.97	7.70
	Measured + Indicated	35,107,900	6,943	36.62	7.26	0.94	7.77
	Inferred	N/A	N/A	N/A	N/A	N/A	N/A

Table 11.5. Mineral Resource Estimates

11.3 CUT-OFF QUALITY, ASSUMED COST AND SALES PRICE

Quality limits for the Mineral Resource estimates were discussed under Section 11.1.

11.4 QUALIFIED PERSONS CLASSIFICATION OF MINERAL RESOURCES

11.5 UNCERTAINTY IN THE MINERAL RESOURCE ESTIMATES

Uncertainty in the Mineral Resource estimates was previously discussed in in subsection Mineral Resource Classification and Uncertainty under Section 11.1.

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11.6 QUALIFIED PERSONS POTENTIAL INFLUENCES AFFECTING MINERAL RESOURCE ESTIMATES

Due to the confines of the LSA, factors including contract term or likelihood of economic extraction, lignite sales price, and quality parameters/limits have far less risk of being affected than a mineral sold on the open market. Nonetheless some risks still need to be addressed. Additional exploration may positively or negatively affect Mineral Resource estimates. Furthermore, Mineral Resource estimates may be materially affected by a significant change in the assumptions including general mining costs and land control. New regulations may impose additional economic factors, delays to future permit renewals, or restrictions to physical estimation boundaries. Although Coyote has a long-term LSA, numerous regulatory authorities, along with well-funded political and environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation. As a result of such activities, the Coyote Station owners could prematurely retire Coal Creek Station. Any premature facility closure could have a material adverse effect on the mineral resource estimates. The QP is not aware of any specific factors that would currently materially affect the prospect of economic extraction.

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12.0 MINERAL RESERVE ESTIMATES

12.1 KEY ASSUMPTIONS, PARAMETERS, AND METHODS

The following key assumptions, parameters, and methods describe how the QP converted the mineral resources to mineral reserves. All recoverable lignite required to fulfill the contractual obligations of the LSA are contained within the LOM Plan pit extents (Figure 12.1 Life-of-Mine Map). The criteria used to estimate the recoverable reserves contained within the LOM pits as estimated by Coyote include:

–Mining costs of $2.27/mmBTU;

–Minimum minable lignite thickness: 2.5 feet;

–Maximum burden depth: approximately 150 feet;

–Mining dilution parameters defined in Table 13.2

–Lignite density of 80 lb/ft3

–Recovery factor of 90%

The price and other economic assumptions used to estimate the recoverable reserves are supported by the existing all-requirements LSA and the life-of-mine plan associated with that contract. Compensation to Coyote under the LSA includes reimbursement of all mine operating costs plus a contractually-agreed fee based on the amount of coal delivered. Coyote Station is located directly next to the Coyote Creek Mine (i.e. a mine-mouth operation) and 100% of the required coal to operate the Coyote Station is sourced from the Coyote Creek Mine.

Criteria for determination of Mineral Reserve estimate are justified in further details in the discussion of run-of-mine tonnages under Section 13.0 of this TRS.

Methods to develop the LOM Plan are as follows:

A workplan forecast is developed to determine the schedule and estimated delivery requirements of Coyote Power Station by month for the first year of the LOM Plan and then by year until the end of the LOM Plan.

To determine initial tonnages for consideration of Mineral Reserves, factors including the maximum economical strip ratios are applied to the geologic model used to define Mineral Resources. Coyote engineers then project mining pits in Carlson mining software following pit design parameters discussed under Section 13.0 of this TRS. Projections are directed to the topography from the lowest mineable lignite seam. Highwalls are normally projected at 53-degrees and endwalls are projected at 45-degrees. Volumes of burden and lignite tonnages with associated quality parameters are exported to monthly and yearly averages. The exported data is then brought into Excel spreadsheets to summarize topsoil, subsoil, overburden, and coal tons.

–Equipment mechanical and operational availabilities estimated based on historical production;

–Historic production rates of each piece of equipment;

–Fleet capacity including limiting production factors;

–New and/or retiring equipment and;

–Auxiliary equipment allotments.

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The total hours, allotted volumes, tonnages and quality by period are the primary inputs for the Coyote financial model.

The resulting lignite schedule from the financial model based on the specified delivery schedule determine the Mineral Resources that carry through to become Mineral Reserves.

SEC S-K 1300 Technical Report Summary

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Figure 12.1. Life-of-Mine Map.

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Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

12.2 MINERAL RESERVE ESTIMATES

BASIS FOR MINERAL RESERVE ESTIMATE

This Item discloses the Mineral Reserve estimates for the Coyote Creek Mine based on the QP’s detailed evaluation of the modifying factors as applied to indicated or measured mineral resources, which demonstrate economic viability of the Coyote Creek Mine property. The estimated Mineral Reserves are in accordance with the definitions of “Mineral Reserve” as describe by the S-K 1300 regulations (17 CRF 229.1300) as:

The reference point at which Mineral Reserves are defined, is the point of sale to the Coyote Station Power Plant. This location is on the Coyote Station Power Plant belt 1 conveyor belt where the certified conveyor belt scale weighs the number of tons of lignite delivered over a 24-hour period. The belt 1 conveyor belt is immediately after the Coyote Creek Mine coal handling facility.

The LOM plan included annual stripping and lignite production qualities and quantities. Annual production costs were estimated based on the mine plan quantities, surface mining methods, equipment fleets in use, and unit prices that have been proven by historical production at the Coyote Creek Mine. The current mining methods, used at the Coyote Creek Mine since inception, are planned to continue until enough lignite reserve is depleted to fulfill the contractual obligations of the LSA for fuel supply to the Coyote Station Power Plant.

12.3 CUT-OFF QUALITY AND SALES PRICE

Cut-off quality and price were previously discussed in Section 12.1.

12.4 MINERAL RESERVE STATEMENT

The effective date of Mineral Reserve estimates is December, 31, 2021.

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			Quality
			Calorific Value	Moisture	Ash	Sulfur	Sodium in Ash
Mine/Area	Reserve Classification	Tonnage	(Btu/lb)	(wt%)	(wt%)	(wt%)	(wt%)
	Proven	31,202,000	6,943	36.63	7.25	0.94	7.78
Coyote Creek	Probable	3,905,900	6,942	36.55	7.39	0.97	7.70
	Total	35,107,900	6,943	36.62	7.26	0.94	7.77

Table 12.1. Mineral Reserve Estimates.

12.5 MULTIPLE COMMODITY MINERAL RESERVE

Coyote Creek Mine is a single commodity Mineral Reserve.

12.6 QUALIFIED PERSON’S OPINION ON RISK FACTORS THAT

COULD MATERIALLY AFFECT MINERAL RESERVE ESTIMATES

The Coyote Creek Mine has been in operation for over 5 years. Since this is an established operation, the deposit, mining, and environmental aspects of the Project are very well understood. The knowledge for the Coyote Creek Mine is based on the collective experience of personnel from CCMC’s site operations and technical disciplines gained during years of lignite mining at this location and others. This knowledge is supported by production data and observations at the Coyote Creek Mine.

The LOM plan included annual stripping and lignite production qualities and quantities. Annual production costs were estimated based on the mine plan quantities, surface mining methods, equipment fleets in use, and prices based on historical production at the Coyote Creek Mine. The current mining methods, used at the Coyote Creek Mine since inception, are planned to continue until enough lignite reserve is depleted to fulfill the contractual obligations of the LSA for fuel supply to the Coyote Station.

Risks include changes in customer demand for any reason, including, but not limited to, dispatch of power generated by other energy sources ahead of coal, fluctuations in demand due to unanticipated weather conditions, regulations or comparable policies which may promote planned and unplanned outages at the Coyote Station Power Plant, economic conditions, including an economic slowdown and a corresponding decline in the use of electricity, governmental regulations and/or inflationary adjustments which could have a material adverse effect on Coyote's mineral reserve estimates.

At the time of this TRS, the QP is not aware of any specific factors that would currently materially affect the prospect of economic extraction.

Uncertainty in the Mineral Resource estimates was previously discussed in in subsection Mineral Resource Classification and Uncertainty under Section 11.1.

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Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

13.0 MINING METHODS

The Coyote Creek Mine has been in operation for over 5 years. Since this is an established operation, the deposit, mining, and environmental aspects of the Project are very well understood. The geological knowledge is based on the collective experience of personnel from Coyote Creek Mine operations geology, mining, and other technical disciplines gained during years of coal/lignite mining at Coyote Creek Mine and other operations in North Dakota.

The lignite at Coyote Creek Mine surface mining operation is recovered using dragline and conventional truck and shovel mining methods due to the proximity of the lignite to the surface and the physical characteristics of the deposit. Mining operations includes; suitable plant growth material (SPGM) removal, replacement and storage, overburden removal, lignite production, and spoil backfill and grading. In the development phase, drainage and water control were established (see Water Management under Section 17.0), and then the required infrastructure consisting of power, mine office and maintenance facilities, lignite stockpile facilities, and roadways were established.

13.1 ANNUAL AND TOTAL LIGNITE PRODUCTION

The Coyote Creek Mine is designed to supply a maximum of 2.5 million tons but generally supplies approximately 1.7 to 2.0 million tons of lignite per year to the adjacent Coyote Station Power Plant through 2040. Actual production is dictated by customer utilization. Approximately 36 Mt of lignite is expected to be mined and sold from 2022 through 2040 bringing the projected 25-year LOM tonnage to approximately 46 Mt since the mine’s inception. An outline of these tons are shown in Figure 12.1. Life-of-Mine Map.

13.2 TYPE AND GENERAL MINING METHOD

The Coyote Creek Mine is a single lignite seam surface mining operation, which currently encompasses approximately 8,444 acres within the permitted areas.

The primary overburden removal units for a typical mining sequence at the Coyote Creek Mine include:

–one 75-cubic yard, electric-powered walking dragline;

–two tractor scrapers;

–five 700-850-horsepower track-type dozers and;

–one 18-cubic yard, hydraulic excavator

–one 18-cubic yard, front-end loader

–a fleet of 100-ton, end-dump, haul trucks.

Typical digging methods are shown in Figure 13.1 and 13.2. Lignite is severed and loaded by a front-end loader.

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Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

Figure 13.1. Range Diagram – Single-pass method with chopcut

Figure 13.2. Range Diagram – Excavator Prebench

Coyote use standard surface mining techniques to extract lignite. Suitable plant growth material (SPGM) will generally be removed by tractor-scrapers and/or a front end loader or excavator and truck fleet. The SPGM will either be stockpiled in areas designated for topsoil or subsoil stockpiles, or will be directly respread onto regraded areas.

Once all overburden has been removed, the coal surface is cleaned with a rubber-tired or track dozer. The coal seam is then ripped with a 10-foot shank mounted on a track dozer. The coal is ripped to a size that can be most

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effectively loaded into the haul trucks. Coal will be loaded by a front-end loader and hauled by trucks. The coal is hauled from the pit to an unprocessed coal storage pile adjacent to the coal processing facility. A rubber-tire dozer feeds coal from the unprocessed coal storage pile to the apron feeder which feeds the primary crusher at the coal processing facility. The coal is then crushed to a prescribed size and transported on a conveyor to the Coyote Station Power Plant.

After the coal is removed, overburden from the next pit is spoiled into the empty pit, and the mining operation evolves into a reclamation operation. Regrading of spoils will occur so that no more than four spoil peaks are standing at any one time, except in isolated instances in which out of pit spoil must remain to complete reclamation. SPGM will be replaced, generally by tractor-scrapers and front-end loader or excavator and truck fleets after final grade approval has been acquired. Areas to be respread will be staked at 100 foot intervals to mark topsoil and subsoil thickness or respread without staking by using GPS equipment in bulldozers spreading soil. Farm-type equipment will be used to revegetate and maintain reclaimed areas.

13.3 RUN OF MINE TONNAGES

Recoverable Run of Mine (R-O-M) tonnages at the Coyote Creek Mine meet the following conditions:

–Minimum mining thickness: 4.0 ft;

–Maximum burden depth: approximately 150 feet;

–Average lignite density: approximately 80 lb/ft3

The average lignite quality on an As Received (AR) basis through the LOM is projected to be:


Calorific Value (Btu/lb)			6820
Moisture (wt%)			35.19
Ash (wt%)			9.35
Sulfur (wt%)			0.90
Sodium in ash (wt%)			6.14

Table 13.1. Projected LOM Quality.

Mining dilution is determined by an analysis of the geologic model, the coal core data, and the as-delivered coal analyses from the power plant. Roof and floor samples from the coal cores have been periodically collected and analyzed. Statistical analysis has shown that the quality parameters in the roof and floor samples are much more variable than those in the coal seams. Due to this variability, the roof and floor analyses have been used to develop average qualities, with typical distribution ranges.

The geologic model based on the coal core data are is evaluated to establish average yearly coal qualities, based on the actual historical yearly mining areas. These yearly coal qualities (from the model) are then compared to the yearly as-delivered analyses from the power plant.

It should be noted that this procedure of estimating mining dilution is also including the sampling bias in the power plant’s coal sampling systems and other plant specific variables. This means that the dilution estimates are designed to incorporate the biases and variables within the specific power plant.

Mining dilution was initially determined from like coal at a neighboring location. Later, the drilling data was compared to actual as-delivered quality data and confirmed that the original dilution parameters remained applicable with only slight adjustments. Dilution parameters are applied to all lignite seams and are outlined herein:

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Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022


Structural (Roof and Floor)
	Loss (ft)	0.30
	Gain (ft)	0.41


Quality (Roof and Floor)
	Density (lb/ft3)	150
	Calorific Value (Btu/lb)(MAF)	10,000
	Moisture (wt%)	20.00
	Ash (wt%)(Dry)	85.00
	Sulfur (wt%)(MAF)	1.00

Table 13.2. R-O-M Dilution Parameters.

Recovery rate of the coal seam is 90% and determined from various comparisons between surveyed severed tons, haul truck payloads, delivered tons (Coyote Station), and modeled tons accounting for dilution and minimum mining thickness.

13.4 ENGINEERING STUDIES – DESIGN PARAMETERS

PIT DESIGN

In reference to the 2015 geotechnical engineering report “Geotechnical Review for Coyote Creek Mine” prepared for Coyote Creek Mining Company, L.L.C. a factor of safety of 1.2 was used as the minimum factor for design and modeling. Actual observed field conditions have closely mirrored the stability calculations in that study.

If the overburden consists of consolidated claystone or siltstone, this study indicates that for highwalls up to 80 feet in height, a minimum factor of safety of 1.20 is achieved by keeping highwall slope angles between 50 and 60 degrees. The stability of the highwall is affected by the glacial till thickness as well as slope. By minimizing the glacial till thickness, greater stability for the highwall can be achieved. A factor of safety of 1.20 can be maintained for highwalls up to 80 feet with glacial till thickness of 10 feet maximum with entire highwall at 55 degrees. If glacial till thickness approaches 20 feet the tills must be sloped back at 40 degrees to maintain stability.

In areas where the overburden is not consolidated claystone or siltstone, a 20 foot wide offset bench may be built as soon. The bench will replace laying the highwall back in areas with less favorable ground conditions such as localized discontinuities or fracture plains in the overburden. The benches will serve to minimize individual rock falls from entering active work areas in the pit. Coyote Creek does not anticipate using benches often but will adopt this method when necessary.

In those areas where overburden thickness exceeds 85 feet. a prebenching operation will be utilized. Prebenching not only to reduce the overall overburden thickness for the dragline, but also to reduce the till thickness of the bench, significantly enhancing the highwall stability for the dragline. Coyote Creek will utilize constant observation and monitoring of the highwalls during prebenching to determine necessary slope angles that will be used by the dragline, and also during the dragline operations to ensure safe slope creation and identification of any weaker areas. Monitoring will also identify any other localized discontinuities or fracture planes in the overburden that may require additional highwall angle layback or prebenching for the dragline.

Spoil is sloped at a safe angle of repose, which is generally between 30 and 35 degrees. Spoil stability is generally affected by the surface on which the spoil is dumped, the height that spoil is stacked, and whether the spoil is wet or dry. The pit floor is cleaned of any water, mud, or snow prior to spoil placement. The floor may also be ripped and/or tipped away from the highwall.

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SPOIL STABILITY STUDIES

The initial spoil stability study title “Geotechnical Review for Coyote Creek Mine” by BARR Engineering Co. was completed in October 2015. This study contains a section that pertains to spoil stability which influences operation plans for production and reclamation. The slope stability analysis was conducted using SLOPE/W, a computer-modeling program developed by GEO-SLOPE International, Ltd. SLOPE/W uses limit equilibrium theory to compute a factor of safety for earth and rock slopes. It can use a variety of methods to compute the factor of safety of a slope while analyzing complex geometry, stratigraphy, and loading conditions. Phreatic surfaces were set by a defined piezometric line based on a review of zones of saturation in the upper Beulah Lignite aquifer. The dry
condition assumes no saturation within the spoil and the wet condition applied a phreatic surface 20 feet above the pit floor and decreasing in elevation as the phreatic surface approaches the spoil pile toe. The spoil stability results for various heights and with or without phreatic surfaces can be found in Table 13.3. An example of a slope stability analysis done by Barr is presented in Figure 13.3.

Table 13.3. Spoil Stability Results

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Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

Figure 13.3. Soil Model Outputs. (Barr Engineering Co., 2015)

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13.5 HAUL ROADS, RAMPS AND DRAGLINE WALKWAYS

Typical sections for haul roads, spoil ramps, and highwall ramps are presented in Figure 13.4. Haul roads and spoil ramps are typically designed to a width of 84 feet to allow for two-way traffic. In some circumstances, temporary one-way roads may be established with proper signage. Dragline walkways must be a minimum of 100 feet wide, and are designed with no crown.

Figure 13.4. Typical sections for running surfaces.

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Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

13.6 PERSONNEL AND MAJOR EQUIPMENT

Coyote Creek Mine employs approximately 26 full-time maintenance staff, 56 full-time equipment operators, and 24 full-time staff. In addition to the full-time employees Coyote Creek has a few part time or seasonal employees as well.

A list of major and auxiliary equipment used at the Coyote Creek Mine is shown below and will be used, as needed, for all aspects of the operations.

1 Dragline (75 yard)

6 Bulldozers (140 to 850-hp class)

1 Bulldozers (rubber-tired)

3 Road Graders

2 Tractor Scrapers

1 Front-end Coal Loader (30 cy class)

1 Front-end Overburden Loader (18 cy class)

3 Bottom-Dump Coal Haulers (240 ton class)

6 Overburden Trucks (100 ton class)

3 Water Trucks (5,000 to 20,000 gallon class)

1 Hydraulic Backhoe (18 cy yard class)

1 Backhoes (3 cy class)

1 200 ton Lowboy and Tractor

1 Cable Moving Tractors

1 Coal Sample Drill

1 Dump Truck (15-ton class)

2 Pumps and Water Supply Tanks

1 Front-end Loader (6 yard class)

1 Mobile Crane (75 ton class)

1 Portable Air Compressor

1 Fuel Truck

1 Boom Truck

2 Welding Trucks

1 Service and Lube Truck

1 Fuel Tank Farm

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4 Forklifts

2 Field Maintenance Trucks

6 Portable Water Pumps (diesel)

2 Portable Generator

14 Pickups

2 Crew Vans

1 Ambulance

2 ATV’s

2 Skid Steer

1 Lot Reclamation Equipment (tractors, seeders, cultivators, crimpers, rock pickers,

mulcher)

10 Auxiliary Lights

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Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

14.0 PROCESSING AND RECOVERY METHODS

No mineral processing is performed.

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Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

15.0 INFRASTRUCTURE

The Coyote Creek Mine public utility lines and facilities locations are presented in Figure 15.1 (Infrastructure Map).

Coyote Creek Mine purchases power from Roughrider Electric and MDU. A 115kV powerline leaves a switchyard located adjacent to Coyote Station. The power line then runs overhead along the north portion of the permit boundary. An MDU substation comes from that line to feed Coyote Creek Mine’s dragline. Coyote Creek Mine’s coal handling facility is also fed from a substation off MDU’s 115kV powerline. The Shop/Office complex is fed from a Roughrider Electric substation.

Potable water for the mine office facilities is supplied by the Southwest Water Authority.

Coyote Creek Mine utilizes an aerobic sanitary waste treatment lagoon system for office effluent. The lagoon system is regulated by the ND Department of Environmental. Effluent from portable restrooms is collected by licensed septic pumpers and disposed of according to state law.

Recycled water from the nearby Coyote Station is used for washing equipment in the facilities wash bay and fire hydrant use. All other office water is supplied by the South West Water Pipeline, including several pastures taps for livestock watering.

Sedimentation ponds P-06-03, P10-01, P10-02, P30-02, P30-04 and P31-01 are permitted for Beneficial Water Use by the ND State Water Commission and serve as the water source for dust suppression. In addition, there is a water load-out station connected to the Coyote Station water supply that can also be used for dust suppression.

Lignite will be mined and transported to the coal handling facility. The coal can either be stockpiled for future use delivered to the customer. From the coal pits, a front-end loader and fleet of 240-ton bottom dump coal trucks are utilized to extract the coal. A system of permanent haul roads is utilized to transport the coal from the pits to the coal handling facilities. To access the coal handling facility, an overpass was constructed on County Road 12 to pass over Coyote Creek Mine’s haul road. Public roads are not used for the transport of lignite to Coyote Station. Mine site haul routes are depicted in Figure 15.1 (Facilities Map).

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

Figure 15.1. Infrastructure Map.

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Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

16.0 MARKET STUDIES

16.1 MARKETS

The primary market for the Coyote Creek Mine lignite is the adjacent Coyote Station Power Plant for which the mine was developed. The Coyote Creek Mine mines lignite coal which is typically higher in moisture with a lower BTU value. This precludes transporting the fuel as a viable option to expand market share, thus no known marketing studies have been conducted for the Coyote Creek Mine.

16.2 MATERIAL CONTRACTS

Coyote Creek Mine is a fully developed and functioning mining operation. All aspects of the mining, haulage and delivery of lignite to the Coyote Station Power Plant are handled by Coyote. Coyote Creek Mine is a mine-mouth project where the lignite is delivered directly to the power plant using off highway haul trucks. All production from the mine is delivered to Coyote Station under a long-term LSA. The term of the existing LSA terminates in 2040. Under the LSA, Coyote receives a contractually-agreed fee based on the amount of lignite delivered. While Coyote is responsible for all mine operations, the Coyote Station Owners are responsible for funding all mine operating costs and guaranteeing all of the capital required to build and operate the mine. This contract structure eliminates exposure to spot coal market price fluctuations. No other material outside contracts are required to provide this service. No material contracts with affiliated parties are in place. Coyote is an active operation and all material contracts are in place for the continued operation of the mine.

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Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

17.0 ENVIRONMENTAL STUDIES, PERMITTING, AND PLANS, NEGOTIATIONS, OR AGREEMENTS WITH LOCAL INDIVIDUALS OR GROUPS

17.1 ENVIRONMENTAL AND BASELINE STUDIES

–Geology

–Surface Water Hydrology

–Ground Water Hydrology

–Soil Resources

–Alluvial Valley Floors

–Fish and Wildlife Resources

–Climatological Data

–Air Resources

–Aquatic Ecology

–Streams and Wetlands

–Terrestrial Ecology

–Threatened and Endangered Species

–Land Use

–Cultural and Historical Resources

–Transportation Facilities

–Public Health

–Hazardous and Solid Waste

–Prime Farmland

17.2 WASTE DISPOSAL, SITE MONITORING, AND WATER MANAGEMENT

WASTE DISPOSAL

No processing of lignite occurs at the Coyote Creek Mine; therefore, no lignite processing or tailing wastes have been or will be generated.

SITE MONITORING

Coyote Creek Mine has sampling plans for areas that are required to be monitored on a regular basis including water (ground and surface water) sampling, and soil sampling. Coyote Creek Mine is required to conduct routine groundwater, surface water and soil sampling in accordance with SMCRA and NDPDES permit requirements. Surface and groundwater monitoring occur both within the active mine area as well as in adjacent, undisturbed areas upstream and downstream of the active mining operations. Coyote Creek Mine also conducts routine soil sampling to ensure the reclaimed environment meets regulatory chemical and textural requirements. The water and soil data are submitted to NDPSC and NDDEQ in accordance with permit requirements.

Coyote Creek Mine will continue to monitor surface water, groundwater, and soils in accordance with all permit requirements until such time mining and reclamation activities are complete and NDPSC has released the entire project from the reclamation performance bond requirements. This release can only happen once Coyote Creek Mine has quantitatively demonstrated that the reclaimed areas meet performance criteria detailed in the mining permit. Once the reclamation performance bond is released, Coyote Creek Mine will have no further site monitoring requirements.

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Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

WATER MANAGEMENT

Coyote Creek Mine currently holds two North Dakota Pollution Discharge Elimination System (NDPDES) permits which are comparable to the National Pollution Discharge Elimination System (NPDES) permit. NDPDES Permit ND0026697 is an individual permit which establishes effluent limits for water being discharged from the mine sedimentation ponds. Currently, 18 sedimentation ponds are in use at the Coyote Creek Mine for the collection and treatment of surface water runoff from areas disturbed by mining. Water samples are collected and analyzed once per pond discharge on a monthly basis. These samples are then delivered to the nearby MVTL’s certified lab for analysis. Water quality results are reported semi-annually to NDDEQ. Sedimentation ponds are discharged either by pumping or via a draw down valve.

NDPDES Permit NDR32-0000 is a general permit authorizing discharge of stormwater associated with mining, extraction or paving materials. This permit is used for areas of small runoff, such as roads, which are not contained within the watershed of a sedimentation pond. For these areas, a Storm Water Pollution and Prevention (SWPP) plan has been developed to discuss Best Management Practices (BMPs) implemented for the reduction of erosion and sedimentation as well as a Spill Prevention, Control, and Countermeasures (SPCC) plan.

17.3 PERMITS

The Coyote Creek Mine is operating under the state of North Dakota Surface Coal Mining and Reclamation Permit NACC-1302, Renewal 1. The permit was issued by the state of North Dakota under delegated authority of the United States Department of the Interior, Office of Surface Mining Reclamation Enforcement (OSMRE) Surface Mining Control and Reclamation Act (SMCRA).

In addition to the mining permits, Coyote Creek Mine is required to obtain and maintain numerous other regulatory permits and approvals. A list of active permits at the Coyote Creek Mine is provided below.

•Surface Coal Mining Permit NACC-1302

Approved: October 22, 2014

State of North Dakota

Public Service Commission

600 East Boulevard, Dept. 408

Bismarck, ND 58505-0480

•MSHA 32-001028 – Coyote Creek Mine Identification Number

Issued: March 10, 2014

Mine Safety and Health Administration

U.S. Department of Labor

P. O. Box 25367

Denver, Colorado 80225-0367

•Ground Control Plan

ID #32-01028

Effective: November 5, 2015

Mine Safety and Health Administration

U.S. Department of Labor

P. O. Box 25367

Denver, Colorado 80225-0367

•NDPDES Discharge Permit ND-0026697

Issued: November 12, 2014

Renewed: October 1, 2019

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North Dakota Department of Environmental Quality

Environmental Health Section

918 East Divide Avenue

Bismarck, North Dakota 58501-1947

•NDPDES Storm Water Permit NDR32-0000

Issued: January 1, 2015

Renewed: January 1, 2020

North Dakota Department of Environmental Quality

Division of Water Quality

918 East Divide Avenue

Bismarck, North Dakota 58501-1947

•Air Pollution Control Permit to Operate #016017

Issued: November 4, 2016

North Dakota Department of Environmental Quality

Division of Air Quality

918 East Divide Avenue

Bismarck, North Dakota 58501-1947

•Air Pollution Control Permit to Construct PTC15001

Issued: January 7, 2015

North Dakota Department of Environmental Quality

Division of Air Quality

918 East Divide Avenue

Bismarck, North Dakota 58501-1947

•Temporary Water Use Permit #ND2021-20629

Issued: July 6, 2021

•Conditional Use for Coal Excavation and Mining, and Certificate of Zoning Compliance

Case 13-11-02 – Issued December 4, 2013 (For Permit NACC-1302)

Case 13-12-02 – Issued December 19, 2013 (For Permit NACC-1302)

Case 14-07-01 - Issued August 6, 2014 (For Permit NACC-1302)

Case 15-01-01 - Issued January 21, 2015 (For Permit NACC-1302)

Mercer County Board of Commissioners

P.O. Box 39

Stanton, North Dakota 58571

•Department of the Army

Permit No. NWO-2012-2475-BIS

Issued: May 21, 2018

U.S. Army Corps of Engineers, Omaha District

Bismarck Regulatory Office

3319 University Drive

Bismarck, North Dakota 58504

•Radio Station Authorization

FCC Registration #: 0024390122

Issued: May 11, 2015

Federal Communications Commission

Wireless Telecommunications Bureau

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45 L Street NE

Washington, DC 20554

17.4 RECLAMATION BOND REQUIREMENTS

Coyote Creek Mine is required to post a performance bond per NDCC 38-14.1-16 of the regulations. Bonding is calculated based on a consolidated mine wide worst-case scenario with an estimated reclamation cost of $22.5 million (MM). The Coyote Creek Mine has actually secured $23.3 MM through a surety bond.

17.5 PLANS, NEGOTIATIONS, OR AGREEMENTS WITH LOCAL INDIVIDUALS OR GROUPS

Coyote Creek Mine has secured agreements with all third parties that are necessary to conduct mining operations in accordance with applicable law.

17.6 MINE CLOSURE PLANS

Coyote Creek performs contemporaneous reclamation activities in the normal course of operations. All final mine closing is funded by Coyote Station Owners in a reclamation trust account, current estimated future mine closing expenses and accumulated funds total $24.9 million. To the extent Coyote Creek performs final mine reclamation, it will be compensated for providing those services in addition to receiving reimbursement from the Coyote Station owners for costs incurred. Although the mineable lignite within the Coyote Creek coal field will not be exhausted, the production period is tied to the current LSA with the Coyote Station Owners and is based on the projected life of the plant which is expected to operate until 2040. After deliveries cease in 2040, the mine will be required to complete remediation and reclamation of any remaining disturbed areas. Appropriate material will be stockpiled to fill the final pit to the approved post topography design. Final reclamation and closure activities will begin in 2041. The NDPSC permits for mining areas detail post production reclamation activities and long-term management plans for mined lands and all disturbed areas.

17.7 QUALIFIED PERSON’S OPINION OF ADEQUECY OF CURRENT PLANS

There are no outstanding permits related to the LOM plan awaiting regulatory approval. Coyote currently has all permits in place for the Coyote Creek Mine to operate and adhere to a mine plan projected through 2040. Federal Mine Plan Approval is still required from OSMRE to mine Federal Coal. Absent of any regulatory changes out of Coyote’s control, the QP does not anticipate hurdles for approval of future renewal applications. The QP bases this opinion on the mine’s demonstrated success meeting regulatory requirements. No NOVs have been issued at the Coyote Creek Mine in the past three years. Proper monitoring plans in accordance with QA/QC procedures have been in place at the Coyote Creek Mine since the mine’s inception and are documented through regular reporting to NDDOH. Furthermore, appropriate bonding and closure plans are in place.

17.8 DESCRIPTION OF ANY COMMITMENTS OT ENSURE LOCAL PROCUREMENT AND HIRING

Purchasing endeavors to place orders with regards to dependability and service records of the supplier, the nature of the guaranty and warranty of the product, its price, and quality. Preference is given to suppliers who are developing new and improved products or equipment, or designing and developing a special product, specifically for Coyote Creek Mine. Consideration is also provided to local suppliers near the Coyote Creek Mine. Suppliers must have a reputation of adhering to specifications and delivery schedules.

Positions at the Coyote Creek Mine are posted with North Dakota Job Service for priority availability to all veterans and other job seekers.

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Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

18.0 CAPITAL AND OPERATING COSTS

18.1 OPERATING COSTS

Annual production costs were estimated in conjunction with the mining methods discussed in Section 13 to satisfy the contractual terms of the LSA. All costs were estimated based on the most recent LOM tonnage requirement provided by Coyote Station. Operating costs include operating, maintenance, and staff labor, materials and supplies, fuel, equipment repairs, outside contractors, administration, royalties, and all required taxes. All costs are escalated at various rates depending on the predicted performance of the Consumer/Producer Price Index with 2021 being the base year.

The model used to estimate the operating costs to a PFS level of study is based on historical costs and performance measures that have been maintained by Coyote Creek Mine since its inception, along with supplemental data from other NACoal mines in the region. These costs are reviewed on an annual basis to account for changes in site conditions or the operating plan. This information was then used to estimate the projected costs for the Life of Mine (LOM) plan until the end of the current LSA in 2040. Table 18.1 provides a summary of the assumptions that were used to develop these projected costs.


	Annual Average
Dragline Overburden*	14,930,697	CY
Truck/Shovel/Scraper Overburden*	4,957,684	CY
Dozer Push Overburden*	1,200,000	CY
Stripping Ratio	10.4
Delivered Tons	1,918,575	Ton
Lignite cost per Delivered Ton	$2.27	/MMBtu

Quality:
Heating Value	6820	BTU/LB
Moisture	35.19%
Sulfur	0.90%
Ash	9.35%
Sodium in Ash	6.14%

*Includes re-handle

Table 18.1. Cost Assumptions.

All costs including mine development, overburden removal, severing of lignite, reclamation, maintenance and handling of stockpiled lignite and delivery to the neighboring power plant along with the necessary maintenance required to keep all equipment operating safely and efficiently are paid by the Coyote Station Owners. Coyote Creek Mine submits a 5 year plan that is approved by the Coyote Station Owners. The Coyote Station Owners are responsible for funding all mine operating costs, including final mine reclamation, and providing or guaranteeing all of the capital required to build and operate the mine. Coyote Creek is paid a management fee per ton of coal delivered. The LSA specifies the indices and mechanics by which fees change over time, generally in line with broad measures of U.S. inflation. The LSA eliminates exposure to spot coal market price fluctuations.

A total cost of coal over the remaining term of the LSA is shown in Table 18.2. Cost of Coal. Historical data was used to determine the estimated ratio of direct and indirect costs. Indirect costs include; support wages and benefits, medical insurance, power (demand), outside services, short term rentals, miscellaneous, property tax, coal lease maintenance, property and liability insurance, office costs, travel costs, depreciation and amortization, and interest expense. Direct costs include; workforce wages and benefits, supervisory wages and benefits, supplies, fuel, major repairs, power (usage), outside services, short term rentals, miscellaneous, royalties, severance tax, federal reclamation fee, stockpile variance and management fee/profit.

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Table 18.2. Cost of Coal.

18.2 CAPITAL COSTS

Capital Costs were estimated to a PFS level of study based on vendor quotes, historical land purchases, mine development costs, mitigation costs and other costs. Capital costs include only equipment expenditures as no future land acquisitions or mine area development are projected. Future capital costs to fulfil the remaining term of the LSA are estimated to be $44,999,400, however; as required under the LSA, these expenditures will be reimbursed by the Coyote Station Owners. There are risks regarding the capital costs estimates, including escalating costs of raw materials, equipment availability and timing due to either production delays or supply chain gaps. Capital expenditures are detailed in Table 18.3.

Table 18.3. Capital Costs.

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

19.0 ECONOMIC ANALYSIS

19.1 KEY ASSUMPTIONS, PARAMETERS AND METHODS

The primary key assumption in economic viability of the Coyote Creek Mine is the continued operation of Coyote Station and the resultant required annual deliveries. The analysis of economic viability of the Coyote Creek Mine is supported by the existing all-requirements LSA and the life-of-mine plan associated with that contract. Compensation required under the LSA includes reimbursement of all mine operating costs plus a contractually-agreed fee based on the amount of coal delivered. Coyote Station is located directly next to the Coyote Creek Mine (i.e. a mine-mouth operation) and 100% of the required coal to operate Coyote Station is sourced from the Coyote Creek Mine.

The Coyote Creek Mine could be negatively impacted by the decisions of the Coyote Stations owners. In September 2021, one of Coyote Stations owners, Otter Tail Power Company, filed its 2022 Integrated Resource Plan in Minnesota and North Dakota which included its intent to start the process of withdrawal from its 35 percent ownership interest in the Coyote Station power plant with an anticipated exit from the plant by December 31, 2028. Any decision by Coyote Creek’s customers to reduce operations or prematurely close Coyote Station would have a material adverse effect on the economic viability of the Coyote Creek Mine and the economic feasibility and viability of the coal reserves associated with the Coyote Creek Mine.

Additional key assumptions include:

–The LOM production plan is based primarily on surface mining methods including a truck and shovel, scraper, dozer and dragline operations;

–Total number of employees – 106

–Diesel price was $2.28 at the beginning of 2022. This price was escalated at an annual rate of 2.3%

–Wages and benefits were escalated at an annual rate of 3%

–Supply costs were escalated at an annual rate of 2.3%

–Power costs for the dragline and coal handling facility were escalated at an annual rate of 3%

19.2 ANNUAL CASH FLOWS

The Net Present Value, Internal Rate of Return and capital payback period is not applicable due to the ongoing nature of this project and cost-plus feature of the LSA. The cost-plus nature of the LSA provides assurance that all costs incurred by the Coyote Creek Mine will be reimbursed by the Coyote Station Owners and negates any risk of loss to the Coyote Creek Mine and allows the mine to remain cash flow positive in 2022 and remain so through the end of the term of the LSA in 2040.

19.3 SENSITIVITY ANALYSIS

Over the history of the mine, CCMC has monitored historical fixed and variable costs. Increased tonnage decreases the overall production cost per ton as fixed costs can be spread over additional tons. For every 100,000 ton annual reduction, costs are estimated to increase approximately $0.80/ton. The inverse has also been shown such that for every 100,000 ton annual increase, the overall cost of production is estimated to be reduced by approximately $0.80/ton.

Coyote Creek Mine’s profit correlates proportionally with the actual increase or decrease in tonnage required for the Coyote Station Power Plant as compensation from the Coyote Station Owners includes reimbursement of all mine operating costs plus a contractually-agreed fee based on the amount of coal delivered It was assumed all costs in the LOM are economical for the power plant based on approval of Coyote Creek Mine’s Life-of-Mine plan. One of the largest cost components within the plan that does fluctuate is diesel fuel. A cost of $2.40 per gallon for diesel price

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

was used. If the cost of diesel goes up 50%, the final average selling price of coal will go from $2.27 per million BTU to $2.35 per million BTU.

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

20.0 ADJACENT PROPERTIES

Dakota Westmoreland Beulah Mine is a coal mining operation adjacent to the Coyote Creek Mine. No information disclosed by Westmoreland was identified or utilized for this report. No public drilling information was available or sourced for the development of the geological model.

The drilling and exploration activities at the Coyote Mine defines the lignite geology, Mineral Resources and Mineral Reserves. Due to this and the relatively simple geology at the Coyote Mine, material changes to the Mineral Resource estimates and Mineral Reserve estimates are not likely if adjacent property information is included in future estimates.

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

21.0 OTHER RELEVANT DATA AND INFORMATION

In the QPs opinion, all material information has been stated in the above sections of this TRS.

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

22.0 INTERPRETATIONS AND CONCLUSIONS

All data provided in this TRS is appropriate and has been utilized for the start-up, and continual operation of the Coyote Creek Mine. Coyote Creek Mine has been a producing mine since 2016.

The projected plant life and subsequent LOM plan are projected to continue operations through 2040.

Based on the LSA, factors including contract term or likelihood of economic extraction, lignite sales price, and quality parameters/limits have far less risk of being affected than a mineral sold on the open market. Nonetheless some risks still need to be addressed. Additional exploration may positively or negatively affect Mineral Resource estimates. Although rare but possible, unexpected coal subcrops and seam pinchouts can affect tonnage estimates. Furthermore, Mineral Resource estimates may be materially affected by a significant change in the assumptions including general mining costs. New regulations may impose additional economic factors, delays to future permit renewals and applications, or restrictions to physical estimation boundaries. Although Coyote has a long-term LSA, regulatory changes or lower carbon initiatives could affect either the Coyote Creek Mine or Coyote Station Owners. Also numerous regulatory authorities, along with well-funded political and environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation. As a result of such activities, Coyote Station could prematurely retire. Any premature facility closure could have a material adverse effect on the mineral resource estimates.

The QP is not aware of any specific factors that would currently materially affect the prospect of economic extraction.

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

23.0 RECOMMENDATIONS

Continue current practices and reconciliations of actual to budget lignite recoveries, qualities, and costs. Update LOM plan projections and economic analyses accordingly.

Additional exploration drilling is recommended to convert any inferred and indicated resources to measured resources. These estimates are already included in future cost projections/LOM Plan.

Otter Tail Power Company has stated it plans to sell its 35% share of the Coyote Station power plant by 2028. Continue to monitor future disclosures or announcements by Otter Tail Power Company in regards to its withdrawal from its 35 percent ownership interest in the Coyote Station power plant.

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

24.0 ADDITIONAL REFERENCES

Barr Engineering. (2015, October). Geotechnical Review for Coyote Creek Mine.

Barr Engineering. (2017, October). Ground Control Plan and Pit Slope Stability Condition Review.

Bluemle, J. 1983. Geologic and Topographic Bedrock Map of North Dakota.

CRIRSCO. (2019, November). The International Reporting Template.

Croft, M. G. Groundwater Resources, Mercer and Oliver Counties, North Dakota, Bulletin 56 - Part II. I-II-III - North Dakota Geological Survey, Bismarck, North Dakota, 1973.

Groenewold, Hemish, Cherry, Rehm, Meyer, Winczewski. Geology and Geohydrology of the Knife River Basin and Adjacent Areas of North Dakota. Report of Investigation #64, North Dakota Geological Survey, 1979.

NACoal. (2020, November 30). 2020 Lignite Coal Quality Round Robin.

SEC S-K 1300 Technical Report Summary

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

25.0 RELIANCE ON INFORMATION PROVIDED BY THE REGISTRANT

The QPs for this report are employees of the registrant and all information and data was sourced from the registrant or studies commissioned by the registrant.

SEC S-K 1300 Individual Property Disclosure

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

PROPERTY LOCATION

The Coyote Creek Mine is located approximately nine miles southwest of Beulah, North Dakota (ND), in Mercer County, which is approximately 75 miles northwest of Bismarck, ND. The main entrance to the mine will be accessed by traveling south of Beulah on Highway 49 for five miles, then west on County Road 25 for four miles. The general location of the Coyote Creek Mine is shown in Figure 1.1 (Location of Coyote Creek Mine). The Coyote Station Power Plant is adjacent to the Coyote Creek Mine.

Figure 1.1. Location of the Coyote Creek Mine.

LOCAL RESOURCES AND INFRASTRUCTURE

The towns of Beulah, Hazen, and Stanton along with other smaller communities are within a 40-mile radius of the Coyote Creek Mine and provide a vast supply and employment base. A vast supply and employment base also come from some of the major cities of Bismarck, Minot, and Dickinson, all of which are less than 100 miles away from the mine.

The Coyote Creek Mine sources power for mine office facilities and operations from Roughrider Electric Cooperative and Montana-Dakota Utilities Co., and water for the mine office facilities from the Southwest Water

SEC S-K 1300 Individual Property Disclosure

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

Authority. Fuel for equipment is supplied by multiple local vendors. The Coyote Creek Mine has all supporting infrastructure for mining operations.

North Dakota’s freight rail service is largely provided by Burlington Northern Santa Fe Railway and Canadian Pacific Railway.

LEASES

Coyote holds 86 leases granting the right to mine approximately 8,129 acres of coal interests and the right to utilize about 15,168 acres of surface interests. In addition, Coyote owns in fee about 160 acres of surface interests and has four easements on approximately 352 acres. The leases, easements, and deeds are recorded at the Mercer County courthouse and are a matter of public record. Substantially all of the leases were acquired over the past 15 years and have continuation provisions that generally permit the leases to be continued beyond their fixed terms. The leases obligate Coyote to make payments based on the amount of lignite mined from the subject property. Most royalty rates range from $.08 - $.16 per ton of lignite mined and are subject to escalation in accordance with the escalator provision in the lease. Payments may also include surface damage payments and advanced or minimum royalty payments. Production royalties are calculated monthly based on surveys and are generally paid on a quarterly basis, although in certain situations royalties are paid monthly. Table 1.1 Identification of Leases, shows the name or identifying number of each lease, or sublease, the nature and extent of Coyote’s title to, or interest in, the associated property, and expiration date of each lease. While Coyote’s leases include a primary, or fixed, term (as set forth in Table 1.1), they include continuation provisions that allow for their continuation beyond their primary terms so long as operations and/or reclamation activities are continuing.

Table 1.1 Identification of Leases

Lease Id

Lease Type

Lease Date

Lease Expiration Date

22-02578

Coal Lease

3/24/2014

3/23/2044

22-02579

Coal Lease

3/24/2014

3/23/2044

22-02580

Coal Lease

3/24/2014

3/23/2044

22-02581

Coal Lease

3/24/2014

3/23/2044

22-02582

Coal Lease

3/24/2014

3/23/2044

22-02583

Coal Lease

3/24/2014

3/23/2044

22-02584

Coal Lease

3/24/2014

3/23/2044

22-02585

Coal Lease

3/24/2014

3/23/2044

22-02586

Coal Lease

3/24/2014

3/23/2044

22-02587

Coal Lease

3/24/2014

3/23/2044

22-02588

Coal Lease

3/24/2014

3/23/2044

22-02589

Coal Lease

3/24/2014

3/23/2044

SEC S-K 1300 Individual Property Disclosure

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

22-02590

Coal Lease

3/24/2014

3/23/2044

22-02591

Coal Lease

3/24/2014

3/23/2044

22-02592

Coal Lease

3/24/2014

3/23/2044

22-02593

Coal Lease

11/1/2020

10/31/2040

22-02505

Coal Lease Agreement

9/29/2010

9/28/2030

22-02513

Coal Lease Agreement

10/14/2010

10/13/2030

22-02514

Coal Lease Agreement

10/14/2010

10/13/2030

22-02515

Coal Lease Agreement

10/20/2010

10/19/2030

22-02516

Coal Lease Agreement

10/12/2010

10/11/2030

22-02517

Coal Lease Agreement

10/13/2010

10/12/2030

22-02518

Coal Lease Agreement

10/22/2010

10/21/2030

22-02519

Coal Lease Agreement

10/28/2010

10/27/2030

22-02520

Coal Lease Agreement

10/15/2010

10/14/2030

22-02521

Coal Lease Agreement

10/22/2010

10/21/2030

22-02525

Coal Lease Agreement

11/13/2010

11/12/2030

22-02526

Coal Lease Agreement

11/4/2010

11/3/2030

22-02527

Coal Lease Agreement

11/1/2010

10/31/2030

22-02528

Coal Lease Agreement

11/4/2010

11/3/2030

22-02529

Coal Lease Agreement

11/11/2010

11/10/2030

22-02530

Coal Lease Agreement

11/15/2010

11/14/2030

22-02531

Coal Lease Agreement

11/1/2010

10/31/2030

22-02532

Coal Lease Agreement

12/3/2010

12/2/2030

22-02533

Coal Lease Agreement

12/3/2010

12/2/2030

22-02534

Coal Lease Agreement

12/3/2010

12/2/2030

22-02538

Coal Lease Agreement

12/29/2010

12/28/2030

22-02539

Coal Lease Agreement

12/29/2010

12/28/2030

22-02540

Coal Lease Agreement

12/29/2010

12/28/2030

22-02541

Coal Lease Agreement

12/29/2010

12/28/2030

22-02542

Coal Lease Agreement

12/29/2010

12/28/2030

22-02543

Coal Lease Agreement

12/29/2010

12/28/2030

22-02544

Coal Lease Agreement

1/26/2011

1/25/2031

22-02545

Coal Lease Agreement

1/28/2011

1/27/2031

22-02546

Coal Lease Agreement

1/10/2011

1/9/2031

22-02547

Coal Lease Agreement

1/1/2011

12/31/2030

22-02548

Coal Lease Agreement

2/15/2011

2/14/2031

22-02549

Coal Lease Agreement

3/3/2011

3/2/2031

22-02550

Coal Lease Agreement

2/28/2011

2/27/2031

22-02552

Coal Lease Agreement

3/15/2011

3/14/2031

22-02554

Coal Lease Agreement

12/3/2010

12/2/2030

22-02560

Coal Lease Agreement

7/25/2011

7/24/2031

22-02563

Coal Lease Agreement

12/20/2011

12/19/2031

22-02564

Coal Lease Agreement

12/16/2011

12/15/2031

22-02565

Coal Lease Agreement

12/16/2011

12/15/2031

22-02566

Coal Lease Agreement

1/11/2012

1/10/2032

22-02567

Coal Lease Agreement

2/28/2012

2/27/2032

22-02568

Coal Lease Agreement

3/29/2012

3/28/2032

22-02569

Coal Lease Agreement

5/15/2012

5/14/2032

22-02570

Coal Lease Agreement

5/24/2012

5/23/2032

SEC S-K 1300 Individual Property Disclosure

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

22-02571

Coal Lease Agreement

6/19/2012

6/18/2032

22-02572

Coal Lease Agreement

5/21/2012

5/20/2032

22-02573

Coal Lease Agreement

5/10/2012

5/9/2032

22-02574

Coal Lease Agreement

7/30/2013

7/29/2033

22-02575

Coal Lease Agreement

9/17/2013

9/16/2033

22-02576

Coal Lease Agreement

10/7/2013

10/6/2033

22-02577

Coal Lease Agreement

2/10/2014

2/9/2034

22-01466

Exploration Contract & Coal Lease

3/28/1975

3/27/2016

22-01467

Exploration Contract & Coal Lease

3/28/1975

3/27/2016

22-02501

Surface & Coal Lease Agreement

9/3/2010

9/2/2030

22-02508

Surface & Coal Lease Agreement

9/29/2010

9/28/2030

22-02509

Surface & Coal Lease Agreement

9/29/2010

9/28/2030

22-02510

Surface & Coal Lease Agreement

9/29/2010

9/28/2030

22-02511

Surface & Coal Lease Agreement

9/29/2010

9/28/2030

22-02512

Surface & Coal Lease Agreement

10/5/2010

10/4/2030

22-02523

Surface & Coal Lease Agreement

11/5/2010

11/4/2030

22-02537

Surface & Coal Lease Agreement

12/29/2010

12/28/2030

22-02556

Surface & Coal Lease Agreement

5/23/2011

5/22/2031

22-02558

Surface & Coal Lease Agreement

7/25/2011

7/24/2031

22-02559

Surface & Coal Lease Agreement

7/25/2011

7/24/2031

22-02561

Surface & Coal Lease Agreement

7/25/2011

7/24/2031

22-02562

Surface & Coal Lease Agreement

10/27/2011

10/26/2031

22-02503

Surface Lease Agreement

9/10/2010

9/9/2030

22-02522

Surface Lease Agreement

11/8/2010

11/7/2030

22-02535

Surface Lease Agreement

12/10/2010

12/9/2030

22-02557

Surface Lease Agreement

8/5/2011

8/4/2031

SEC S-K 1300 Individual Property Disclosure

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

MINE HISTORY, OPERATIONS AND ENCUMBRANCES

The Coyote Creek Mining Company, L.L.C. (Coyote), a subsidiary of The North American Coal Corporation (NACoal) is the owner and operator of the Coyote Creek Mine, an active lignite surface mining operation in production status. NACoal is a wholly-owned subsidiary of NACCO Industries (NACCO). The Coyote Creek Mine generally produces approximately 1.5 million to 2.5 million tons of lignite coal annually when Coyote Station is operating at anticipated levels. All production from the mine is delivered to the Coyote Station owned by Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Company and Northwestern Corporation.

Original exploration of the Coyote Creek Mine area was conducted by NACoal from beginning in the 1970’s. Consolidation Coal Company (CONSOL) conducted some exploration drilling in the vicinity in 1978. In 2012, NACoal conducted a major drilling program to define the reserves within the proposed Coyote Creek permit area, and have continued drilling programs since. The surface coal mining permit was approved in 2014, and initial boxcuts were opened in 2016.

Fill-in drilling programs are routinely conducted by Coyote for the purpose of refining guidance related to ongoing operations. It is common practice at the Coyote Creek Mine to tighten the drilling density with-in the three to four-year block ahead of active operations to an average drill hole spacing of 660-feet. However, additional exploration may also be scheduled in areas farther out to increase confidence in future mine plan projections.

The geology encountered at the Coyote Creek Mine is stratigraphic in nature with depositional sequences of sands, silts, clays, and lignite. The bedrock is masked by residual soils, slopewash, and/or glacial drift. The vertical repetition of geologic strata facilitated a straightforward setting to establish and study the baseline geological, geochemical, geotechnical, and geohydrological conditions at the Coyote Creek Mine.

Operationally, overburden removal is accomplished using scrapers, dozers, front end loaders, excavators, truck fleets, and a dragline. Lignite is mined with front end loaders, and loaded into haul trucks to transport to the coal stockpile.

The mine office facilities and original equipment fleets at the Coyote Creek Mine were constructed, acquired, or purchased during the development stage of the mine. The facilities and equipment are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, Coyote evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.

The total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2020 is $140.9 Million.

The Coyote Creek Mine currently has no significant encumbrances to the property. No NOVs have been issued at the Coyote Creek Mine in the past three years. All permitting requirements related to surface coal mining for the projected life-of-mine (LOM) plan are currently in place.

MINERAL RESOURCES AND RESERVES

MINERAL RESOURCES

The Mineral Resources have been estimated by applying a series of geologic and physical limits as well as high-level mining and economic constraints. The mining and economic constraints were limited to a level sufficient to support reasonable prospect for future economic extraction of the estimated Mineral Resources. The categorized Mineral Resources are reported in Table 1.2.

SEC S-K 1300 Individual Property Disclosure

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

The effective date of Mineral Resource estimates is December 31, 2021.


			Quality
			Calorific Value	Moisture	Ash	Sulfur	Sodium in Ash
Mine/Area	Resource Classification	Tonnage	(Btu/lb)	(wt%)	(wt%)	(wt%)	(wt%)
	Measured	31,202,000	6,943	36.63	7.25	0.94	7.78
Coyote Creek	Indicated	3,905,900	6,942	36.55	7.39	0.97	7.70
	Measured + Indicated	35,107,900	6,943	36.62	7.26	0.94	7.77
	Inferred	N/A	N/A	N/A	N/A	N/A	N/A

Table 1.2. Mineral Resource Estimates

MINERAL RESERVES

The Mineral Reserves presented in Table 1.3 below were determined to be the economically mineable portion of the measured and indicated Mineral Resources after the consideration of modifying factors related to the mining process. Inferred Mineral Resources were not considered for Mineral Reserves.

The effective date of Mineral Reserve estimates is December 31, 2021.


			Quality
			Calorific Value	Moisture	Ash	Sulfur	Sodium in Ash
Mine/Area	Reserve Classification	Tonnage	(Btu/lb)	(wt%)	(wt%)	(wt%)	(wt%)
	Proven	31,202,000	6,943	36.63	7.25	0.94	7.78
Coyote Creek	Probable	3,905,900	6,942	36.55	7.39	0.97	7.70
	Total	35,107,900	6,943	36.62	7.26	0.94	7.77

Table 1.3. Mineral Reserves

DISCUSSION OF PRIOR RESOURCE AND RESERVE ESTIMATIONS

Previously, reserves for the Coyote Creek Mine were reported under Guide 7. All controlled tonnage that met the general mining parameters were considered for reserves. Mineral Resources were not considered. Furthermore, subcategories of Mineral Resources as measured, indicated, or inferred and Mineral Reserves as proven or probable were not considered. Table 1.4 below summarizes those reported Mineral Reserves at the end of the last two fiscal years.

SEC S-K 1300 Individual Property Disclosure

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022


Coyote Creek Mine
Report Date			Total Tons
1-Jan-21			72,411,342
1-Jan-20			69,590,257
^ The difference in allotment of tons to each category from 2020 to 2021 was due to mining, lease activity, and new geologic evaluations.

Table 1.4. Summary of Prior Mineral Reserves


Coyote Creek Mine	Tonnage
Resource Classification	1-Jan-22	1-Jan-21	Percent Change
Measured	31,202,000	N/A	N/A
Indicated	3,905,900	N/A	N/A
Measured + Indicated	35,107,900	N/A	N/A
Inferred	N/A	N/A	N/A

Reserve Classification	1-Jan-22	1-Jan-21	Percent Change
Proven	31,202,000	N/A	N/A
Probable	3,905,900	N/A	N/A
Total	35,107,900	72,411,342	-52%

Table 1.5. Net difference between 2021 and 2022 reported Mineral Resources and Reserves

“A concentration or occurrence of material of economic interest in or on the Earth’s crust in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. A Mineral Resource is a reasonable estimate of mineralization, taking into account relevant factors, such as cut-off grade, likely mining dimensions, location, or continuity, that, with the assumed and justifiable technical and economic conditions, is likely to, in whole or in part, become economically extractable. It is not merely an inventory of all mineralization drilled or sampled.”

A Mineral Reserve is defined as:

“The economically mineable part of a measured or indicated Mineral Resource, which includes diluting materials and allowances for losses that may occur when the material is mined or extracted.”

Additional impacts to the variance in reported Mineral Resources and Reserves from the January 1, 2021 report date to the January 1, 2022 report date include:

–Coyote severed 2,017,958 tons in 2021.

–Coyote did not acquire or terminate leases in 2021.

SEC S-K 1300 Individual Property Disclosure

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

MATERIAL ASSUMPTIONS FOR MINERAL RESOURCES AND MINERAL RESERVES

Material assumptions and criteria used in the determination of Mineral Resource and Mineral Reserves reported herein are provided within the filed Technical Report Summary (TRS) for the Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine dated February 14, 2022.

SEC S-K 1300 Internal Controls Disclosure

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

EXPLORATION DRILLING - GENERAL

Independent drilling companies are contracted by Coyote Creek Mining Company, L.L.C. (Coyote) to drill/retrieve coal cores for the Coyote Creek Mine. Coyote personnel oversee the retrieval of core samples, then log and properly bag those samples for analysis by a certified third-party laboratory, Minnesota Valley Testing Laboratories, Inc. (MVTL) located in Bismarck, North Dakota.

For the purpose of this discussion, senior geologist and field geologist refer to qualified representatives of Coyote and/or the North American Coal Corporation (NACoal).

QUALITY CONTROL AND QUALITY ASSURANCE PROGRAMS

SAMPLE PREPARATION

A riffled split of 8-mesh coal is placed on a sample tray and weighed. The weights are sent electronically to LIMS for use in the moisture calculation. The tray is placed in an air dry oven and dried overnight. The temperature of the air dry ovens is monitored and recorded daily. The temperature monitoring devices are verified annually. Another riffled split is sealed in a Ziploc bag and retained. The client is notified prior to disposal of the coal core splits.

CONTROLS

Retained samples. Total core runs are double bagged and tagged for quality analyses, thus split samples in the context of a retained sample are not stored at the Coyote Creek Mine. As such, any retained samples, including 8-mesh and 60-mesh, are stored at MVTL, and collected after total core runs have been crushed and mixed. Additionally, it is important to note that lignite tends to be a high moisture coal which oxidizes rapidly and does not have a long shelf life once removed from the ground. If core splits were retained at Coyote Creek Mine, they would not be representative of in-situ coal properties over a relatively short period of time. All of the analyses in the laboratory are performed on the 60-mesh sample or ash prepared from it. The samples are mixed by tumbling prior to each analysis.

SEC S-K 1300 Internal Controls Disclosure

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

Duplicate samples. During the lab analyses MVTL runs regular control measures. For calorific value, moisture, ash, volatile matter, sulfur, ash fusion, mineral analysis of ash, carbon, hydrogen, nitrogen, mercury, and chlorine analyses, one duplicate sample is run for every 10 samples, and a certified reference material (CRM) is analyzed at the beginning and end of each run. For sulfur forms analysis, a laboratory control sample (LCS) and one duplicate analysis is analyzed with each batch. For trace metals, a method blank, laboratory control sample (LCS), and matrix spikes are digested with each batch.

Balances. All balances are calibrated and certified annually by a third-party calibration service. Balances are verified daily using certified weights.

Figure 1.0. NACoal 2020 Round Robin Program Summary. (NACoal, 2020)

CUSTODY

Core samples remain under the supervision of the field geologist until securely stored in the mine warehouse to be shipped to the third-party laboratory, MVTL. The Coyote Creek Mine office and warehouse facilities are secured with user specified fob access and camera surveillance.

SEC S-K 1300 Internal Controls Disclosure

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

Retained samples can be reran for analysis within 6-months for selective parameters. MVTL verifies with Coyote prior to disposal of splits and retained samples.

QUALITY PRECISION AND ACCURACY

Once results are received by Coyote, a visual inspection of results by the senior geologist is followed by a review of summary statistics with the quality of the entire drilling database. Ultimately the results are updated in the geologic model and quality grids are inspected for anomalies. At any point if questionable data is traced back to the laboratory report, the senior geologist may request the lab to rerun a retained sample.

The analytical results from the coal cores collected during Coyote’s exploration programs have proven to be consistent with actual as-delivered quality from the active mining operations at the Coyote Creek Mine. This consistency is based on comparison of historical quality projected from the geologic model for the annual operating plans to actual as-delivered quality indicated by the customer’s samples with analysis computed at MVTL.

VERIFICATION OF ANALYTICAL PROCEDURES

The QP has visited the third-party laboratory on multiple occasions. The QP has received a tour of the full facility from the main offices through the receiving dock/storage room, prep room, and primary laboratory, along with all analytic procedures. The facility is well maintained, and clean. Further details about the laboratory are discussed in section 8.0 of the Technical Report Summary (TRS) for Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine, dated February 14, 2022.

COMPREHENSIVE RISK INHERENT IN THE ESTIMATION OF MINERAL RESOURCES AND RESERVES

Coyote has remained consistent with coal core sampling programs following and documenting procedures that align with coal industry standards. Data collected during drilling exploration programs at the Coyote Creek Mine from 2012 through present, is the sole information available for modeling the lignite deposit for the determination of Mineral Resources for the Coyote Creek Mine. During the drilling and sampling procedure, a variety of factors could materially affect the accuracy and reliability of the results. Some examples include improper surveying of the drill hole collar location and elevation, improper and un-level drill rig set up, improper zeroing out of the elogging tool before commencing geophysical logging, not being able to obtain an elog due to collapsing drill hole conditions, not obtaining 90% recovery of the coal seam cored, allowing the coal core to be exposed for too long before bagging causing a false reduction in moisture and increase in BTU value, and improper record keeping. Most

SEC S-K 1300 Internal Controls Disclosure

Coyote Creek Mining Company, L.L.C. – Coyote Creek Mine February 14, 2022

of these negative factors can be avoided by utilizing skilled and experienced drilling and elogging contractors, having proper QA/QC procedures to follow during sampling, and proper drill hole data verification.

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company

Underwood, North Dakota

Effective Date: December 31, 2021

Report Date: February 14, 2022

Report Prepared by:

The Falkirk Mining Company

2801 1st Street SW

Underwood, ND 58576

Signed by Qualified Persons:

Renee Schultz, PE

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022

TABLE OF CONTENTS


0.0 LIST OF TABLES AND FIGURES			6
0.1 LIST OF FIGURES			6
0.2 LIST OF TABLES			6
0.3.1 CERTIFICATE OF QUALIFIED PERSON, RENEE E. SCHULTZ			7
1.0 EXECUTIVE SUMMARY			9
1.1 PROPERTY DESCRIPTION AND OWNERSHIP			9
1.2 GEOLOGY AND MINERALIZATION			10
1.3 STATUS OF EXPLORATION			10
1.4 DEVELOPMENT AND OPERATIONS			10
1.5 MINERAL RESOURCE ESTIMATE			11
1.6 MINERAL RESERVE ESTIMATE			11
1.7 ECONOMIC ASSESSMENT			12
1.8 PERMITTING REQUIREMENTS			13
1.9 QUALIFIED PERSON’S CONCLUSIONS AND RECOMMENDATIONS			13
2.0 INTRODUCTION			14
3.0 PROPERTY DESCRIPTION			17
3.1 PROPERTY LOCATION			17
3.2 PROPERTY AREA			17
3.3 LEASES AND MINERAL RIGHTS			18
3.4 SIGNIFICANT ENCUMBRANCES TO THE PROPERTY			31
3.5 SIGNIFICANT FACTORS AND RISKS			31
4.0 ACCESSIBILITY, CLIMATE, LOCAL RESOURCES, INFRASTRUCTURE, AND PHYSIOGRAPHY			32
4.1 PHYSIOGRAPHY, TOPOGRAPHY AND VEGETATION			32
4.2 ACCESSIBILITY			32
4.3 CLIMATE			32
4.4 LOCAL RESOURCES AND INFRASTRUCTURE			32
5.0 HISTORY OF THE PROPERTY			33
5.1 PREVIOUS OPERATIONS			33
5.2 EXPLORATION AND DEVELOPMENT HISTORY			33
6.0 GEOLOGICAL SETTING, MINERALIZATION AND DEPOSIT			34

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022


6.1 REGIONAL AND LOCAL GEOLOGY			34
7.0 EXPLORATION			39
7.1 DRILLING EXPLORATION			40
7.1.1 DRILLING METHODS			40
7.1.2 GENERAL DRILLING PROCEDURES			40
7.1.3 DRILLING EXPLORATION PROGRAMS			41
7.2 HYDROGEOLOGIC CHARACTERIZATION			42
7.2.1 GROUNDWATER STUDIES			42
7.2.2 SURFACE WATER STUDIES			45
7.3 EARLY GEOTECHNICAL STUDIES			46
8.0 SAMPLE PREPARATION, ANALYSES, AND SECURITY			50
8.1 SAMPLE COLLECTION AND SHIPMENT			50
8.2 SAMPLE PREPERATION AND ANALYSIS			51
8.3 ASTM Standards			51
8.4 SAFETY			52
8.5 ROUND ROBIN PROGRAMS			52
8.6 BALANCES			52
8.7 SAMPLE RECEIVING AND STORAGE ROOM			52
8.8 PREP ROOM			53
8.9 LABORATORY TESTING			53
8.10 QP STATEMENT ON THE ADEQUACY OF SAMPLE PREPARATION, SECURITY AND ANALYTICAL PROCEEDURES			53
9.0 DATA VERIFICATION			54
9.1 DRILLHOLE DATA VERIFICATION			54
9.2 LIMITATIONS ON DATA VERIFICATION			55
9.3 QP’S STATEMENT OF ADEQUACY OF DATA			55
10.0 MINERAL PROCESSING			56
11.0 MINERAL RESOURCE ESTIMATES			56
11.1 BASIS FOR MINERAL RESOURCE ESTIMATE			56
11.2 STRATIGRAPHIC MODEL			56
11.2.1 HORIZONS			57
11.2.2 QUALITY PARAMETERS AND DENSITY DETERMINATION			57

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022


11.2.3 MODELING PROCESS			58
11.2.4 JUSTIFICATION OF MODELING METHODS			58
11.2.5 QP’s REVIEW AND VALIDATION OF MODEL			58
11.3 MINERAL RESOURCE ESTIMATES			59
11.3.1 LIMITS AND CONSTRAINTS ON THE MINERAL RESOURCE ESTIMATES			59
11.3.2 GENERATION OF PITS SHELLS FOR MINERAL RESOURCE ESTIMATES			60
11.3.3 MINERAL RESOURCE CLASSIFICATION AND CATAGORIZATION			60
11.3.4 MINERAL RESOURCE STATEMENT			62
11.3.5 UNCERTAINTY OF MINERAL RESOURCE ESTIMATES			62
12.0 MINERAL RESERVE ESTIMATES			63
12.1 BASIS FOR MINERAL RESERVE ESTIMATE			63
12.2 MINERAL RESERVE ESTIMATES			63
12.2.1 KEY ASSUMPTIONS, PARAMETERS, AND METHODS			63
12.2.2 MINERAL RESERVE STATEMENT			65
13.0 MINING METHODS			67
13.1 ANNUAL AND TOTAL LIGNITE PRODUCTION			67
13.2 TYPE AND GENERAL MINING METHOD			67
13.3 RUN OF MINE TONNAGES			69
13.4 ENGINEERING STUDIES – DESIGN PARAMETERS			71
13.4.1 PIT DESIGN			71
13.4.2 SPOIL STABILITY STUDIES			72
13.5 HAUL ROADS, RAMPS AND DRAGLINE WALKWAYS			73
13.6 PERSONNEL			74
13.7 MAJOR EQUIPMENT			75
15.0 INFRASTRUCTURE			76
16.0 MARKET STUDIES			76
16.1 MARKETS			76
16.1.1 MATERIAL CONTRACTS			76
17.0 ENVIRONMENTAL STUDIES, PERMITTING, AND PLANS, NEGOTIATIONS, OR AGREEMENTS WITH LOCAL INDUVIDUALS OR GROUPS			77

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022


17.1 PERMITS			77
17.2 ENVIRONMENTAL STUDIES			80
17.3 BASELINE STUDIES			80
17.3.1 GROUNDWATER			80
17.3.2 SURFACE WATER			82
17.3.3 GEOCHEMISTRY			82
17.3.4 ARCHEOLOGY			82
17.3.5 WATERS OF THE US (WOTUS)			83
17.4 WASTE DISPOSAL			83
17.5 SITE MONITORING			83
17.5.1 WATER SAMPLING			83
17.5.2 SOIL SAMPLING			83
17.6 WATER MANAGEMENT			84
17.7 RECLAMATION BOND			84
17.8 PLANS, NEGOTIATIONS, OR AGREEMENTS WITH LOCAL INDIVIDUALS OR GROUPS			84
17.9 MINE CLOSURE PLANS			84
17.10 QP’s OPINION OF ADEQUECY OF CURRENT PLANS			85
17.11 DESCRIPTION OF ANY COMMITMENTS TO ENSURE LOCAL PROCUREMENT AND HIRING			85
18.0 CAPITAL AND OPERATING COSTS			86
18.1 OPERATING COSTS			86
18.2 CAPITAL COSTS			87
19.0 ECONOMIC ANALYSIS			87
19.1 KEY ASSUMPTIONS, PARAMETERS AND METHODS			87
19.2 ANNUAL CASH FLOWS			88
19.3 SENSITIVITY ANALYSIS			88
21.0 OTHER RELEVANT DATA AND INFORMATION			89
22.0 INTERPRETATIONS AND CONCLUSIONS			89
22.1 GEOLOGY AND MINERAL RESOURCE ESTIMATES			89
23.0 RECOMMENDATIONS			89
24.0 ADDITIONAL REFERENCES			90

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022

0.0 LIST OF TABLES AND FIGURES

0.1 LIST OF FIGURES

FIGURE 3.1. LOCATION OF THE FALKIRK MINE

FIGURE 4.1. TOPOGRAPHIC FEATURES OF THE FALKIRK MINE

FIGURE 6.1. GEOLOGIC AND TOPOGRAPHIC BEDROCK MAP OF NORTH DAKOTA (BLUEMLE, 1983)

FIGURE 6.2. STRATIGRAPHIC COLUMN OF THE FALKIRK MINE

FIGURE 6.3. GEOLOGIC CROSS SECTIONS UNDWERWOOD MINE AREA*

FIGURE 6.4. GEOLOGIC CROSS SECTIONS RIVERDALE MINE AREA*

FIGURE 7.1. LOCATION OF DRILL HOLES*

FIGURE 7.2. EXISTING, DESTROYED AND CERTIFIED MONITORING WELL LOCATION MAP*

FIGURE 7.3. LOCATION OF GEOTECHNICAL BORINGS UNDERWOOD MINE AREA

FIGURE 7.4. LOCATION OF GEOTECHNICAL BORINGS RIVERDALE MINE AREA

FIGURE 8.1. NACOAL 2020 ROUND ROBIN PROGRAM SUMMARY. (NACOAL, 2020)

FIGURE 12.1. LIFE OF MINE MAP*

FIGURE 13.1. TYPICAL RANGE DIAGRAM FOR DRAGLINE SINGLE PASS

FIGURE 13.2. TYPICAL RANGE DIAGRAM FOR DRAGLINE SINGLE PASS WITH TRUCK-SHOVEL PREBENCH

FIGURE 13.3. SLOPE STABILITY ANALYSIS (BARR ENGINEERING, 2013)

FIGURE 13.4 TYPICAL SECTIONS FOR HAUL ROADS, RAMPS, AND DRAGLINE WALKWAYS

FIGURE 15.1 LOM INFRATRUCTURE MAP*

* FIGURES ARE LOCATED IN THE SUPPLEMENTAL FIGURES ATTACHMENT

0.2 LIST OF TABLES

TABLE 0.0 QP SECTIONS OF RESPONSIBILITY

TABLE 1.1 MINERAL RESOURCE ESTIMATES

TABLE 1.2 MINERAL RESERVE ESTIMATES

TABLE 3.1 IDENTIFICATION OF LEASES

TABLE 3.2 IDENTIFICATION OF ACQUISITIONS

TABLE 8.1 LIST OF ASTM STANDARDS FOR MVTL

TABLE 11.1 STRATIGRAPHIC HORIZONS

TABLE 11.2 TYPICAL QUALITY PARAMETERS

TABLE 11.3 UNIT COSTS-MINERAL RESOURCE ESTIMATION PARAMETERS

TABLE 11.4 MINERAL RESOURCE CATEGORY DISTANCES

TABLE 11.5MINERAL RESOURCE ESTIMATES

TABLE 12.1 MINERAL RESERVE ESTIMATES

TABLE 13.1 PROJECTED LIFE OF MINE QUALITY

TABLE 13.2 RECOVERY RATES BY SEAM

TABLE 13.3 R-O-M DILUTION PARAMETERS

TABLE 13.4 EFFECTIVE HIGHWALL ANGLE BY DEPTH

TABLE 13.5 LIST OF MAJOR EQUIPMENT

TABLE 17.1 LIST OF ACTIVE PERMITS AT THE FALKIRK MINE

TABLE 18.1 COST ASSUMPTIONS

TABLE 18.2 LOM OPERATING COSTS

TABLE 18.3 CAPITAL COSTS

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022

0.3.1 CERTIFICATE OF QUALIFIED PERSON, RENEE E. SCHULTZ

(a)I am the Senior Mining Engineer at The Falkirk Mining Company in Underwood, ND; a position I have held since 2018. I have been an engineer at Falkirk since 2002.

(b)This certificate applies to the Technical report Summary titled “SEC S-K 1300 Technical Report Summary, The Falkirk Mining Company, Underwood, ND”

(c)I am a Qualified Person(QP) for the purpose of SEC S-K 1300. My qualifications as a qualified person are as follows:

a.I am a graduate of Montana Tech School of Mines and Geology in Butte, MT with a Bachelor of Science in Mining Engineering in 2001

b.I am a Professional Engineer in the state of North Dakota (License Number PE-6256).

c.My relevant experience of over 20 years, for the purpose of the Technical Report Summary, includes 4 years in Surveying, 3 years in Geology/Modeling, and 13 years in Engineering/Mine Planning

d.I am currently employed by The Falkirk Mining Company where I conduct personal inspections of each mining area on a regular basis described in this Technical Report Summary.

e.I am Responsible for the sections listed in Table 0.0 of the Technical Report.

f.I have read SEC S-K 1300 Technical Report Summary requirements. The part of the Technical Report Summary for which I am responsible has been prepared in compliance with this requirement.

g.At the effective date of the Technical Reporrt Summary, the the best of my knowledge, information, and belied, the parts of the Technical Report Summary for which I am responsible, contains all scientific and technical information that is required to be disclosed to make the Technical Report Summary not misleading.

h.I consent to the filing of the Technical Report Summary as an exhibit to NACCO Industries, Inc.’s annual report. I also consent to the use of any quotes of summaries in that annual report to the extent they pertain to the Technical Report Summary sections for which I am responsible.

Dated the 14th day of February, 2022

Renee E. Schultz, PE

The Falkirk Mining Company

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022

The effective date of this Technical Report Summary is December 31, 2021.


QP Name	Sections Responsible For	Signature
Renee E. Schultz	1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24

Table 0.0 QP SECTIONS OF RESPONSIBILITY

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022

1.0EXECUTIVE SUMMARY

This Technical Report Summary (TRS) was prepared for The Falkirk Mining Company (Falkirk) to report Mineral Resources and Mineral Reserves for the Falkirk Mine in McLean County, North Dakota.

1.1 PROPERTY DESCRIPTION AND OWNERSHIP

The Falkirk Mining Company (Falkirk), a wholly-owned subsidiary of North American Coal (NACoal), which is a wholly-owned subsidiary of NACCO, operates the Falkirk Mine in North Dakota. Falkirk is the sole supplier of lignite coal to the CCSPP pursuant to a contract under which Falkirk also supplies approximately 0.3 million tons of lignite coal per year to Spiritwood Station power plant.

The CCSPP and Spiritwood Station are owned by Great River Energy (“GRE”). In May 2020, GRE announced its intent to sell or retire the CCSPP in the second half of 2022 and modify Spiritwood Station to be fueled by natural gas.

On June 30, 2021, GRE entered into an agreement to sell the CCSPP and the adjacent high-voltage direct current transmission line to Bismarck, North Dakota-based Rainbow Energy Center, LLC (“Rainbow Energy”) and its affiliates. The transaction between GRE and Rainbow Energy is subject to the satisfaction of certain conditions, including regulatory approvals associated with the sale of the CCSPP and the related transmission assets and the posting of a performance bond related to final mine reclamation. If the conditions are satisfied, the transaction is expected to close in the first half of 2022.Upon completion of the sale of the CCSPP, the existing Coal Sales Agreement, the existing Mortgage and Security Agreement and the existing Option Agreement between GRE and Falkirk will be terminated. If GRE's efforts to sell the power plant are successful, a new Coal Sales Agreement (“CSA”) between Falkirk and Rainbow Energy will become effective and Falkirk will begin supplying all coal requirements of the CCSPP concurrent with Rainbow Energy’s acquisition of the power plant. Falkirk will no longer make any coal deliveries to GRE’s Spiritwood Station. Falkirk will be paid a management fee and Rainbow Energy will be responsible for funding all mine operating costs and directly or indirectly providing all of the capital required to operate the mine. The CSA specifies that Falkirk will perform final mine reclamation, which will be funded in its entirety by Rainbow Energy. The initial production period is expected to run ten years from the effective date of the CSA, but the CSA may be extended or terminated early under certain circumstances.

For purposes of this TRS, the QP has assumed the transaction with Rainbow Energy occurs. The production period under the new CSA is expected to run ten years from the effective date of the CSA. Although the CSA may be extended or terminated early under certain circumstances, the LOM has been developed assuming a 10-year period.

The Falkirk Mine is located approximately 50 miles north of Bismarck, North Dakota on a paved access road off U.S. Highway 83. Falkirk holds 335 leases granting the right to mine approximately 43,486 acres of coal interests and the right to utilize approximately 24,324 acres of surface interests. In addition, Falkirk owns in fee 40,666 acres of surface interests and 1,789 acres of coal interests. Substantially all of the leases held by Falkirk were acquired in the early 1970s with initial terms that have been further extended by the continuation of mining operations.

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022

1.2 GEOLOGY AND MINERALIZATION

1.3 STATUS OF EXPLORATION

Substantial information has been gathered during exploration drilling programs within the region since the 1960s. These data were the fundamental tools used in characterizing substrate composition, geometry, and structure of the Falkirk Mine lignite deposit prior to mining. Exploration programs described in this TRS have considered the stratigraphic nature of the mineralization for the determination of hole spacing, drilling and sampling method, and quality analyses in order to geologically map and evaluate the structural and quality characteristics of the lignite deposit.

The Falkirk Mine lignite deposit is evaluated on a seam-by-seam basis. Drilling exploration data including geologic lithologies, qualities, and hole locations have been compiled in an electronic, geologic database. Drilling exploration programs conducted at the Falkirk Mine have comprised largely of rotary air/mist/mud drilling methods. Drill holes were geophysically logged for natural gamma, density, caliper, and resistivity responses to obtain data related to the subsurface structure. Coal core samples collected for quality analyses were sent to independent commercial laboratories for testing.

1.4 DEVELOPMENT AND OPERATIONS

The Falkirk Mine is a multiple lignite seam surface mining operation which supplies approximately 7.5 to 8.2 million tons of lignite per year to the adjacent CCSPP. Actual annual production is dictated by customer demand. The CCSPP sends the generated electricity to MISO grid to supply electricity to GRE’s member Co-ops.

The lignite at the Falkirk Mine surface mining operation is uncovered using dragline, dozer, and conventional truck and shovel mining methods due to the proximity of the lignite to the surface and the physical characteristics of the deposit. Lignite is mined using electric cable shovels and large front-end loaders to load a fleet of bottom dump haul trucks and is directly shipped to the CCSPP or placed on the lignite stockpile. The overall average Run of Mine (ROM) quality of the mined lignite seams meets the required power plant quality specifications. Therefore, no mineral processing is performed by Falkirk.

The Falkirk Mine delivered its first coal in 1978, with mine development work taking place in the preceding few years. The Falkirk Mine has, or is currently constructing, all supporting infrastructure for mining operations within the permitted areas.

The Falkirk Mine employs a staff and workforce of approximately 400 employees with fluctuations in employment levels for changes in demand at the CCSPP.

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022

1.5 MINERAL RESOURCE ESTIMATE

The QP based the Mineral Resource estimates for the Falkirk Mine on a stratigraphic geologic model generated from the verified drilling exploration data.

Mineral Resources classification distances from point of measurement for each class are as followed: Measured – less than 1,320 feet, Indicated - from 1,320 feet to 2,640 feet, and Inferred – from 2,640 – 5,280 ft.

There are no reported Mineral Resources at the Falkirk Mine. The economically mineable portions of the Measured and Indicated Mineral Resources within the constraints of the CSA and under lease control have been converted to Mineral Reserves.


			Quality
			Calorific Value	Moisture	Ash	Sulfur
Falkirk Mine	Resource Classification	Tonnage	(Btu/lb)	(%wt)	(%wt)	(%wt)
Underwood Field	Measured	31,599,882	6,417	40.41	7.05	0.57
	Indicated	NA	NA	NA	NA	NA
	Measured + Indicated	31,599,882	6,417	40.41	7.05	0.57
	Inferred	NA	NA	NA	NA	NA
Riverdale	Measured	46,820,901	6,614	39.44	6.37	0.58
Field	Indicated	199,721	6,317	37.10	10.69	0.73
	Measured + Indicated	47,020,623	6,612	39.43	6.39	0.58
	Inferred	NA	NA	NA	NA	NA

Total	Measured	78,420,784	6,534	39.83	6.65	0.57
	Indicated	199,721	6.317	37.10	10.69	0.73
Total	Measured+Indicated	78,620,505	6,534	39.82	6.66	0.57

Table 1.1. Mineral Resource Estimates

1.6 MINERAL RESERVE ESTIMATE

The Mineral Reserves in this TRS were determined to be the economically mineable portion of the Mineral Resources after the consideration of modifying factors related to the mining process which convert Measured Resources to Proven Mineral Resources and Indicated Resources to Probable Mineral Reserves. Inferred Mineral Resources were not considered for Mineral Reserves. A cut-off grade of $2.60/MMBTU has been applied to the Measured and Indicated Resources to upgrade these resources into Proven and Probable Reserves. Mineral Reserves Estimates have been calculated and are shown in Table 1.2.

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022

quality thresholds were met. Recovery rates were applied to the lignite tonnages by seam and then the blocks were sequenced based on a projected total tonnage delivered to the CCSPP through the LOM plan to determine the Measured Resources that would be converted to Mineral Reserves.

This disclosure of Mineral Reserves is based upon the QP’s opinion that the LOM plan and cost estimates has been completed to a Pre-feasibility (PFS) level of accuracy, as defined in 17 Code of Federal Regulations (CFR) Part 229.1300, which includes and supports the QP’s determination of Mineral Reserves.

The Falkirk Mine Mineral Reserve, as of December 31, 2021, is shown in Table 1.2.


			Quality
			Calorific Value	Moisture	Ash	Sulfur
Falkirk Mine	Resource Classification	Tonnage	(Btu/lb)	(%wt)	(%wt)	(%wt)
Underwood	Proven	31,599,882	6,417	40.41	7.05	0.57
Field	Probable	NA	NA	NA	NA	NA
	Total	31,599,882	6,417	40.41	7.05	0.57
Riverdale	Proven	46,820,901	6,614	39.44	6.37	0.59
Field	Probable	199,721	6,317	37.10	10.69	0.73
	Total	47,020,623	6,612	39.43	6.39	0.58

Total Reserves	Proven	78,420,784	6,534	39.83	6.65	0.57
	Probable	199,721	6.317	37.10	10.69	0.73
	Total	78,620,505	6,534	39.82	6.66	0.57

Table 1.2. Mineral Reserve Estimates.

The QP’s opinion on risks related to Mineral Reserve estimates include changes in customer demand for any reason, including, but not limited to, dispatch of power generated by other energy sources ahead of coal, fluctuations in demand due to unanticipated weather conditions, regulations or comparable policies which may promote planned and unplanned outages at the CCSPP, economic conditions, including an economic slowdown and a corresponding decline in the use of electricity, governmental regulations and/or inflationary adjustments which could have a material adverse effect on Falkirk's financial condition, results of operations and cash flows.

At the time of this TRS, the QP is not aware of any specific factors that would materially affect the Mineral Reserve estimates.

1.7 ECONOMIC ASSESSMENT

The current delivery requirements included in the LOM plan are based on the most recent projections from the CCSPP owners. All costs were estimated based on the LOM tonnage requirements.

The model used to estimate the operating costs is based on historical costs and performance measures that have been maintained by the Falkirk Mine since its inception. These costs are reviewed and verified on an annual basis to account for changes in site conditions or the operating plan. This information is then used to estimate the projected costs for the LOM plan.

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022

Capital costs include equipment expenditures, land acquisition, and additional mine area development costs. All capital costs incurred by the Falkirk Mine are reimbursed by the CCSPP owners as required under the terms of the CSA. Should the CSA be extended beyond 2032, additional capital costs would be required and funded by the CCSPP owners.

The primary key assumption in economic viability of the Falkirk Mine is the continued operation of the CCSPP and the resultant required annual deliveries. The analysis of economic viability of the Falkirk Mine is supported by the all-requirements CSA’s and the life-of-mine plan associated with those contracts. Compensation required under the CSA includes reimbursement of all mine operating costs plus a contractually-agreed fee based on the amount of coal delivered. CCSPP is located directly adjacent to the Falkirk Mine (i.e. a mine-mouth operation) and 100% of the required coal to operate the CCSPP is sourced from the Falkirk Mine. The CSA eliminates the Falkirk Mine’s exposure to spot coal market price fluctuations.

1.8 PERMITTING REQUIREMENTS

The Falkirk Mine operates under several permits from the state of North Dakota’s Public Service Commission/Reclamation Division under delegated authority of the United States Department of the Interior, Office of Surface Mining Reclamation Enforcement (OSMRE) Surface Mining Control and Reclamation Act (SMCRA). In addition to the mining permit, Falkirk has secured numerous other permit and agreements, including a National Pollutant Discharge Elimination System (NPDES) permit and an Individual Permit issued by the United States Army Corp of Engineers (USCOE). All permits have been secured and continue to be renewed in a timely fashion.

Falkirk currently has all permits in place for the Falkirk Mine to operate and adhere to a mine plan projected through April 2032. Barring any regulatory changes out of Falkirk’s control, the QP does not anticipate hurdles for approval of future renewal applications.

1.9 QUALIFIED PERSON’S CONCLUSIONS AND RECOMMENDATIONS

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022

2.0 INTRODUCTION

This technical report was prepared for The Falkirk Mining Company (Falkirk) which owns and operates the Falkirk Mine.

The purpose for which this technical report summary was prepared is to report Mineral Resources and Mineral Reserves for the Falkirk Mine located in McLean County, North Dakota.

The sources of information and data contained in the technical report or used in its preparations were supplied by FALKIRK and include data used to produce geologic models, production data, environmental support documents, third-party technical studies, resource and reserve estimates, cost estimates, and economic analyses. A large portion of the technical information is summarized from approved Surface Mining Permits issued by the North Dakota Public Service Commission . Additional references to specific studies and documents are provided in Section 23.0 of this technical report summary (TRS).

Qualified persons (QPs) are employed by FALKIRK and directly oversee the drilling exploration programs, daily operations, and/or financial reports of the Falkirk Mine. As such, inspections are conducted on a regular basis and no individual date of inspection has been identified. Renee E. Schultz is a licensed Professional Engineer, over 20 years of experience in Surveying, Geology/Modeling, and Engineering/Mine Planning, as well as with the economic aspects of each discipline.

This is the first TRS filed to the United States Securities and Exchange Commission (SEC) in accordance with S-K Subpart 1300 regulations, therefore no preexisting technical report summary exists with the SEC. Mineral Resource and Reserve estimations prior to December 31, 2021 were reported in accordance with guidance of Industry Guide 7.

This terms of reference for this TRS include

–US English spelling;

–Imperial units of measure;

–Lignite qualities are presented in weight percent (wt%) and lignite tonnages are present in short tons (2000 lbs);

–Coordinate System is presented in imperial units using the North American Datum 1927 (NAD27), North Dakota State Plane, South Zone;

–Nominal US Dollars as of 2021.

Key Acronyms and definitions for this TRS include:


AR			As-Received Basis
ARO			Asset Retirement Obligation
ASTM			American Society for Testing and Materials
BCY			Bank Cubic Yard
BHTI			Base Horizon Till
BMPs			Best Management Practices
CSA			Coal Sales Agreement
COC			Chain of Custody
COSC			Cost of Severed Coal

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022


CRIRSCO CCSPP			Committee for Mineral Reserves International Reporting Standards Coal Creak Station Power Plant
DMRs			Discharge Monitoring Reports
DTM			Digital Terrain Model
EIS			Environmental Impact Statement
FMC			Falkirk Mining Company
FoS			Factor of Safety
GEA			Geotechnical Engineering Associates
GWMP			Ground Water Monitoring Plan
Lbs			Pounds
LOM			Life of Mine
mg/L			Milligrams per Liter
msl			Mean Sea Level
Mt			Million Tons
MVTL			Minnesota Valley Testing Laboratories
ND			North Dakota
NACoal			The North American Coal Corporation
NOV			Notice of Violation
NPDES			National Pollutant Discharge Elimination System
OSMRE			United States Department of the Interior, Office of Surface Mining Reclamation Enforcement
QA/QC			Quality Assurance/Quality Control
QP(s)			Qualified Person(s)
R-O-M			Run of Mine
R-O-W			Right of Way
SEC			United States Securities and Exchange Commission
SG			Specific Gravity
S-K 1300			SEC’s Subpart S-K 1300 (17 CFR 229.1300)
SPGM			Suitable Plant Growth Material
SPT			Standard Penetration Testing
SWPPP			Storm Water Pollution and Prevention Plan
TDS			Total Dissolved Solids
TRS			Technical Report Summary

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022


TSS			Total Suspended Solids
U.S.			United States
USCS			Unified Soil Classification System
USGS			United States Geological Survey
WOTUS			Waters of the United States

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022

3.0 PROPERTY DESCRIPTION

3.1 PROPERTY LOCATION

The Falkirk Mine is located approximately 4 miles south of Underwood, North Dakota (ND) or approximately 7.5 miles northwest of Washburn, ND, in McLean County, which is approximately 55 miles north of Bismarck, ND. The entrance to the mine is by means of a paved road, 1st Street SW, that is located approximately 2 mile west of Highway 83. The general location of the Falkirk Mine is shown in Figure 3.1 (Location of Falkirk Mine). The CCSPP is adjacent to the Falkirk Mine.

Figure 3.1. Location of the Falkirk Mine.

3.2 PROPERTY AREA

The Falkirk Mine encompasses two Mine Areas – Underwood and Riverdale. The Underwood Mine Area contains mining permits NAFK 8405, 9601, and 8705, while the Riverdale Mine Area contains mining permit NAFK - 9503. The lignite located in each Mine Area that is encompassed in the LOM plan is considered a Mineral Reserve.

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022

Falkirk holds 335 leases granting the right to mine approximately 43,486 acres of coal interests and the right to utilize about 24,324 acres of surface interests. In addition, Falkirk owns in fee about 40,666 acres of surface interests and 1,789 acres of coal interests.

3.3 LEASES AND MINERAL RIGHTS

The name or number and expiration date of each title, claim, mineral right, lease, or option under which Falkirk or an affiliated NACCO company has or will have the right to hold or operate on the property is described on Table 3.1 (Identification of Leases) and Table 3.2 (Identification of Acquisitions).

The leases and deeds are recorded at the McLean County courthouse and are a matter of public record. Substantially all of the leases were acquired in the 1970’s and have been replaced with new leases and/or have continuation provisions that generally permit the leases to be continued beyond their fixed terms. The leases obligate Falkirk to make payments based on the amount of lignite mined from the subject property. Most royalty rates range from $.08 - $.16 per ton of lignite mined. A few leases include annual escalator provisions. Payments may also include surface damage payments and advanced or minimum royalty payments. Production royalties are calculated monthly based on surveys and are generally paid on a quarterly basis, although in certain situations royalties are paid monthly.

Table 3.1 Shows The Falkirk Mining Company leases and Table 3.2 shows the Falkirk Mining Company acquisitions.

Table 3.1. Identification of Leases


Lease Id	Lease Type	Lease Date	Lease Expiration Date

3RO-03637	Coal Lease Agreement	9/18/1997	9/17/2017
3RO-03638	Coal Lease Agreement	10/20/1997	10/19/2017
3RO-03639	Coal Lease Agreement	1/29/1998	1/28/2018
3RO-03641	Surface & Coal Lease Agreement	1/6/1999	1/5/2009
3RO-03645	Surface & Coal Lease Agreement	2/11/2003	2/10/2013
3RO-03646	Coal Lease	10/30/2003	10/29/2033
3RO-03647	Coal Lease	10/30/2003	10/29/2033
3RO-03648	Coal Lease	10/30/2003	10/29/2033
3RO-03649	Coal Lease	10/30/2003	10/29/2033
3RO-03650	Coal Lease	10/30/2003	10/29/2033
3RO-03652	Coal Lease	10/30/2003	10/29/2033
3RO-03653	Coal Lease	10/30/2003	10/29/2033
3RO-03654	Coal Lease	10/30/2003	10/29/2033
3RO-03655	Surface & Coal Lease Agreement	6/9/2004	6/8/2044
3RO-03656	Coal Lease Agreement	2/22/2007	2/21/2047
3RO-03657	Coal Lease Agreement	3/9/2007	3/8/2047
3RO-03658	Surface & Coal Lease Agreement	6/11/2007	6/10/2027
3RO-03659	Surface & Coal Lease Agreement	6/11/2007	6/10/2027

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022


3RO-03660	Surface & Coal Lease Agreement	7/10/2007	7/9/2047
3RO-03661	Coal Lease Agreement	10/4/2007	10/3/2047
3RO-03662	Surface & Coal Lease Agreement	12/13/2007	12/12/2047
3RO-03663	Coal Lease Agreement	9/29/2007	9/28/2047
3RO-03664	Surface & Coal Lease Agreement	3/7/2008	3/6/2048
3RO-03665	Coal Lease Agreement	3/8/2008	3/7/2048
3RO-03666	Coal Lease Agreement	3/7/2008	3/6/2048
3RO-03667	Surface & Coal Lease Agreement	3/20/2008	3/19/2048
3RO-03668	Coal Lease Agreement	6/4/2008	6/3/2048
3RO-03669	Coal Lease Agreement	3/28/2008	3/27/2048
3RO-03670	Surface & Coal Lease Agreement	4/2/2008	4/1/2048
3RO-03671	Coal Lease Agreement	5/31/2008	5/30/2048
3RO-03672	Coal Lease Agreement	6/4/2008	6/3/2048
3RO-03673	Coal Lease Agreement	6/19/2008	6/18/2028
3RO-03674	Surface & Coal Lease Agreement	7/3/2008	7/2/2048
3RO-03675	Coal Lease Agreement	7/3/2008	7/2/2028
3RO-03676	Surface & Coal Lease Agreement	7/18/2008	7/17/2048
3RO-03677	Coal Lease Agreement	7/16/2008	7/15/2048
3RO-03678	Coal Lease Agreement	8/26/2008	8/25/2048
3RO-03679	Surface & Coal Lease Agreement	12/13/2008	12/12/2048
3RO-03680	Surface & Coal Lease Agreement	5/5/2009	5/4/2049
3RO-03681	Coal Lease Agreement	12/17/2009	12/16/2049
3RO-03682	Coal Lease	7/29/2010	7/28/2055
3RO-03683	Coal Lease	7/29/2010	7/28/2055
3RO-03684	Coal Lease	7/29/2010	7/28/2055
3RO-03685	Coal Lease	7/29/2010	7/28/2055
3RO-03686	Coal Lease	7/29/2010	7/28/2055
3RO-03687	Coal Lease	7/29/2010	7/28/2055
3RO-03688	Coal Lease Agreement	5/12/2010	5/11/2050
3RO-03689	Coal Lease Agreement	5/12/2010	5/11/2050
3RO-03690	Surface & Coal Lease Agreement	5/12/2010	5/11/2050
3RO-03691	Surface & Coal Lease Agreement	5/12/2010	5/11/2050
3RO-03692	Surface & Coal Lease Agreement	3/25/2010	3/24/2050
3RO-03693	Coal Lease	7/14/2014	7/13/2019
3RO-03694	Coal Lease Agreement	9/11/2017	9/10/2037
3RO-03695	Coal Lease Agreement	8/21/2017	8/20/2037
3RO-03696	Coal Lease Agreement	9/15/2017	9/14/2037
3RO-03697	Coal Lease Agreement	10/4/2017	10/3/2037
3RO-03698	Coal Lease Agreement	10/7/2017	10/6/2037
3RO-03699	Coal Lease Agreement	10/11/2017	10/10/2037
3RO-03700	Coal Lease Agreement	10/13/2017	10/12/2037
3RO-03701	Coal Lease Agreement	10/10/2017	10/9/2037
3RO-03702	Coal Lease Agreement	9/25/2017	9/24/2037
3RO-03703	Coal Lease Agreement	10/20/2017	10/19/2037
3RO-03704	Coal Lease Agreement	10/23/2017	10/22/2037
3RO-03705	Coal Lease Agreement	12/7/2017	12/6/2037
3RO-03706	Coal Lease Agreement	12/14/2017	12/13/2037

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022


3RO-03707	Coal Lease Agreement	1/26/2018	1/25/2038
3RO-03708	Coal Lease Agreement	3/7/2018	3/6/2038
3RO-03709	Coal Lease Agreement	3/9/2018	3/8/2038
3RO-03710	Coal Lease Agreement	3/15/2018	3/14/2038
3RO-03711	Surface & Coal Lease Agreement	4/16/2018	4/15/2043
3RO-03712	Surface & Coal Lease Agreement	4/17/2018	4/16/2043
3RO-03713	Surface & Coal Lease Agreement	4/19/2018	4/18/2043
3RO-03714	Surface & Coal Lease Agreement	4/20/2018	4/19/2043
3RO-03715	Surface & Coal Lease Agreement	4/23/2018	4/22/2043
3RO-03716	Surface & Coal Lease Agreement	5/25/2018	5/24/2043
3RO-03717	Surface & Coal Lease Agreement	5/29/2018	5/28/2043
3RO-03718	Surface & Coal Lease Agreement	8/8/2018	8/7/2043
3RO-03719	Surface & Coal Lease Agreement	11/1/2018	10/31/2043
3RO-03720	Surface & Coal Lease Agreement	11/6/2018	11/5/2043
3RO-03721	Surface Lease Agreement	1/28/2020	1/27/2040
3RV-03255	Exploration Contract & Coal Lease	9/12/1972	9/11/2013
3RV-03261	Exploration Contract & Coal Lease	8/28/1972	8/27/2013
3RV-03280	Exploration Contract & Coal Lease	8/30/1972	8/29/2013
3RV-03281	Exploration Contract & Coal Lease	8/30/1972	8/29/2013
3RV-03283	Exploration Contract & Coal Lease	9/12/1972	9/11/2013
3RV-03284	Exploration Contract & Coal Lease	9/13/1972	9/12/2013
3RV-03285	Exploration Contract & Coal Lease	9/12/1972	9/11/2013
3RV-03310	Coal Lease	8/15/1962	8/14/2002
3RV-03311	Coal Lease	5/24/1962	5/23/2002
3RV-03316	Coal Lease	6/8/1962	6/7/2002
3RV-03317	Coal Lease	2/12/1964	2/11/2004
3RV-03321	Coal Lease	1/25/1962	1/24/2002
3RV-03322	Coal Lease	2/16/1962	2/15/2002
3RV-03323	Coal Lease	1/12/1967	1/11/2017
3RV-03324	Coal Lease	11/21/1969	11/20/1994
3RV-03325	Coal Lease	1/23/1962	1/22/2002
3RV-03326	Coal Lease	9/11/1962	9/10/2002
3RV-03327	Coal Lease	9/25/1962	9/24/2002
3RV-03329	Coal Lease	5/23/1962	5/22/2002
3RV-03330	Coal Lease	2/16/1962	2/15/2002
3RV-03331	Coal Lease	5/29/1962	5/28/2002
3RV-03332	Coal Lease	1/16/1967	1/15/2007
3RV-03337	Coal Lease	1/26/1962	1/25/2002
3RV-03339	Coal Lease	5/29/1962	5/28/2002
3RV-03340	Coal Lease	2/21/1962	2/20/2002
3RV-03341	Coal Lease	5/25/1962	5/24/2002
3RV-03342	Coal Lease	5/22/1962	5/21/2002
3RV-03345	Coal Lease	2/9/1962	2/8/2002
3RV-03347	Coal Lease	12/8/1969	12/7/1994
3RV-03348	Coal Lease	12/16/1970	12/15/2015
3RV-03355	Coal Lease	11/9/1971	11/8/2016
3RV-03356	Coal Lease	11/9/1971	11/8/1996

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022


3RV-03360	Coal Lease	11/11/1971	11/10/2016
3RV-03362	Coal Lease	11/29/1971	11/28/1996
3RV-03363	Coal Lease	1/24/1972	1/23/1997
3RV-03367	Coal Lease	8/22/1972	8/21/1997
3RV-03378	Coal Lease	11/29/1972	11/28/1997
3RV-03382	Coal Lease	3/6/1973	3/5/1998
3RV-03386	Coal Lease	5/11/1973	5/10/1998
3RV-03387	Coal Lease	8/7/1973	8/6/1998
3RV-03392	Coal Lease	4/25/1974	4/24/2014
3RV-03393	Coal Lease	5/7/1974	5/6/2014
3RV-03399	Exploration Contract & Coal Lease	7/27/1971	7/26/2012
3RV-03407	Coal Lease	6/11/1974	6/10/2014
3RV-03408	Coal Lease	5/28/1974	5/27/2014
3RV-03409	Coal Lease	6/11/1974	6/4/2014
3RV-03410	Coal Lease	6/12/1974	6/4/2014
3RV-03411	Coal Lease	6/5/1974	6/4/2014
3RV-03412	Coal Lease	6/14/1974	6/4/2014
3RV-03416	Coal Lease	6/14/1974	6/4/2014
3RV-03417	Coal Lease	6/12/1974	6/11/2014
3RV-03418	Coal Lease	8/30/1974	8/29/2014
3RV-03420	Coal Lease	9/19/1974	9/18/2014
3RV-03421	Coal Lease	10/12/1974	10/11/2014
3RV-03422	Coal Lease	10/11/1974	10/10/2014
3RV-03423	Coal Lease	11/22/1974	11/21/2014
3RV-03424	Coal Lease	12/5/1974	12/4/2014
3RV-03425	Coal Lease	12/9/1974	12/8/2014
3RV-03426	Coal Lease	12/10/1974	12/9/2014
3RV-03427	Coal Lease	12/11/1974	12/10/2014
3RV-03428	Coal Lease	12/31/1974	12/30/2014
3RV-03429	Coal Lease	12/30/1974	12/29/2014
3RV-03430	Coal Lease	12/15/1974	12/14/2014
3RV-03431	Coal Lease	1/2/1975	1/1/2015
3RV-03433	Coal Lease	3/11/1975	3/10/2015
3RV-03436	Exploration Contract & Coal Lease	8/19/1972	8/18/2013
3RV-03437	Exploration Contract & Coal Lease	8/18/1972	8/17/2013
3RV-03439	Exploration Contract & Coal Lease	8/30/1972	8/29/2013
3RV-03442	Exploration Contract & Coal Lease	9/5/1972	9/4/2013
3RV-03444	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3RV-03447	Exploration Contract & Coal Lease	8/21/1972	8/20/2013
3RV-03450	Exploration Contract & Coal Lease	8/31/1973	8/30/1994
3RV-03451	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3RV-03452	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3RV-03454	Exploration Contract & Coal Lease	9/12/1972	9/11/2013
3RV-03455	Exploration Contract & Coal Lease	9/12/1972	9/11/2013
3RV-03456	Exploration Contract & Coal Lease	9/11/1972	9/10/2013
3RV-03457	Exploration Contract & Coal Lease	8/31/1972	8/30/2013
3RV-03458	Exploration Contract & Coal Lease	9/12/1972	9/11/2013

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022


3RV-03459	Exploration Contract & Coal Lease	9/12/1972	9/11/2013
3RV-03460	Exploration Contract & Coal Lease	8/21/1972	8/20/2013
3RV-03461	Exploration Contract & Coal Lease	9/11/1972	9/10/2013
3RV-03465	Exploration Contract & Coal Lease	5/26/1972	5/25/2013
3RV-03472	Coal Lease	8/19/1971	8/18/1996
3RV-03482	Coal Lease	6/25/1974	6/24/2014
3RV-03483	Coal Lease	6/25/1974	6/24/2014
3RV-03484	Coal Lease	6/25/1974	6/24/2014
3RV-03485	Coal Lease	6/25/1974	6/24/2014
3RV-03486	Coal Lease	6/25/1974	6/24/2014
3RV-03501	Exploration Contract & Coal Lease	5/26/1972	5/25/2013
3RV-03504	Exploration Contract & Coal Lease	5/25/1972	5/24/2013
3RV-03523	Exploration Contract & Coal Lease	5/22/1972	5/21/2013
3RV-03526	Exploration Contract & Coal Lease	5/27/1972	5/26/2013
3RV-03528	Exploration Contract & Coal Lease	5/24/1972	5/23/2013
3RV-03529	Exploration Contract & Coal Lease	5/25/1972	5/24/2013
3RV-03532	Exploration Contract & Coal Lease	5/23/1972	5/22/2013
3RV-03539	Exploration Contract & Coal Lease	6/5/1972	6/4/2013
3RV-03542	Exploration Contract & Coal Lease	5/24/1972	5/23/2013
3RV-03543	Exploration Contract & Coal Lease	5/25/1972	5/24/2013
3RV-03547	Exploration Contract & Coal Lease	5/24/1972	5/23/2013
3RV-03550	Exploration Contract & Coal Lease	5/30/1972	5/29/2013
3RV-03554	Exploration Contract & Coal Lease	5/23/1972	5/22/2013
3RV-03568	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3RV-03569	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3RV-03600	Exploration Contract & Coal Lease	7/23/1971	7/22/2012
3RV-03601	Exploration Contract & Coal Lease	7/21/1971	7/20/2012
3RV-03609	Exploration Contract & Coal Lease	7/21/1971	7/20/2012
3RV-03611	Exploration Contract & Coal Lease	8/6/1971	8/5/2012
3RV-03624	Coal Lease	1/19/1982	1/18/2022
3RV-03625	Coal Lease	1/19/1982	1/18/2022
3UN-03006	Exploration Contract & Coal Lease	9/23/1971	9/22/2012
3UN-03007	Exploration Contract & Coal Lease	9/23/1971	9/22/2012
3UN-03008	Exploration Contract & Coal Lease	3/3/1973	3/2/2014
3UN-03009	Exploration Contract & Coal Lease	7/23/1971	7/22/2012
3UN-03010	Exploration Contract & Coal Lease	7/22/1971	7/21/2012
3UN-03011	Exploration Contract & Coal Lease	11/22/1972	11/21/2013
3UN-03017	Exploration Contract & Coal Lease	7/22/1971	7/21/2012
3UN-03019	Exploration Contract & Coal Lease	3/3/1973	3/2/2014
3UN-03023	Exploration Contract & Coal Lease	7/22/1971	7/21/2012
3UN-03026	Lease	10/1/1971	9/30/2011
3UN-03027	Exploration Contract & Coal Lease	9/22/1971	9/21/2012
3UN-03032	Exploration Contract & Coal Lease	5/18/1973	5/17/2014
3UN-03035	Exploration Contract & Coal Lease	8/5/1971	8/4/2012
3UN-03040	Exploration Contract & Coal Lease	10/5/1971	10/4/2012
3UN-03041	Exploration Contract & Coal Lease	8/10/1978	8/9/2011
3UN-03043	Exploration Contract & Coal Lease	10/7/1971	10/6/2012

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022


3UN-03045	Exploration Contract & Coal Lease	10/9/1971	10/8/2012
3UN-03050	Coal Lease	8/24/1977	8/15/2027
3UN-03051	Coal Lease	8/24/1977	8/23/2027
3UN-03053	Exploration Contract & Coal Lease	7/29/1971	7/28/2012
3UN-03054	Lease	8/22/1973	8/21/1998
3UN-03057	Exploration Contract & Coal Lease	9/23/1971	9/22/2012
3UN-03058	Exploration Contract & Coal Lease	7/24/1971	7/23/2012
3UN-03059	Exploration Contract & Coal Lease	7/26/1971	7/25/1992
3UN-03060	Exploration Contract & Coal Lease	10/5/1971	10/4/2012
3UN-03061	Exploration Contract & Coal Lease	7/27/1971	7/26/1992
3UN-03066	Exploration Contract & Coal Lease	7/28/1971	7/27/2012
3UN-03067	Exploration Contract & Coal Lease	10/1/1971	9/30/2012
3UN-03071	Exploration Contract & Coal Lease	7/27/1971	7/26/2012
3UN-03077	Exploration Contract & Coal Lease	7/27/1971	7/26/2012
3UN-03079	Exploration Contract & Coal Lease	7/24/1971	7/23/2012
3UN-03082	Exploration Contract & Coal Lease	7/20/1971	7/19/2012
3UN-03083	Exploration Contract & Coal Lease	7/21/1971	7/20/2012
3UN-03084	Exploration Contract & Coal Lease	7/20/1971	7/19/2012
3UN-03085	Exploration Contract & Coal Lease	1/30/1973	1/29/2014
3UN-03088	Exploration Contract & Coal Lease	7/27/1971	7/26/2012
3UN-03096	Exploration Contract & Coal Lease	7/29/1971	7/28/2012
3UN-03102	Exploration Contract & Coal Lease	9/28/1971	9/27/1992
3UN-03114	Exploration Contract & Coal Lease	9/30/1971	9/29/2012
3UN-03115	Exploration Contract & Coal Lease	7/29/1971	7/28/2012
3UN-03117	Exploration Contract & Coal Lease	9/28/1971	9/27/2012
3UN-03123	Exploration Contract & Coal Lease	7/22/1971	7/21/2012
3UN-03126	Exploration Contract & Coal Lease	7/22/1971	7/21/2012
3UN-03128	Exploration Contract & Coal Lease	7/31/1971	7/30/2012
3UN-03129	Exploration Contract & Coal Lease	8/6/1971	8/5/2012
3UN-03130	Exploration Contract & Coal Lease	9/27/1971	9/26/2012
3UN-03132	Exploration Contract & Coal Lease	7/20/1971	7/19/2012
3UN-03135	Exploration Contract & Coal Lease	10/4/1971	10/3/2012
3UN-03137	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3UN-03139	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3UN-03140	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3UN-03141	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3UN-03142	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3UN-03143	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3UN-03154	Exploration Contract & Coal Lease	8/16/1973	8/15/1994
3UN-03155	Exploration Contract & Coal Lease	10/10/1973	1/9/1994
3UN-03191	Coal Lease	5/14/1974	5/13/2014
3UN-03196	Coal Lease	8/19/1971	8/18/1996
3UN-03197	Coal Lease	6/25/1974	6/24/2014
3UN-03198	Coal Lease	6/25/1974	6/24/2014
3UN-03199	Coal Lease	6/25/1974	6/24/2014
3UN-03200	Coal Lease	6/25/1974	6/24/2014
3UN-03201	Coal Lease	6/25/1974	6/24/2014

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022


3UN-03204	Lease	3/27/1980	3/26/1990
3UN-03205	Lease	3/27/1980	3/26/1990
3UN-03206	Lease	3/27/1980	3/26/1990
3UN-03207	Lease	3/27/1980	3/26/1990
3UN-03208	Coal Lease	1/19/1982	1/18/2022
3UN-03209	Coal Lease	1/19/1982	1/18/2022
3UN-03220	Coal Lease	11/15/1972	11/14/1997
3UN-03221	Coal Lease	11/15/1972	11/14/1997
3UN-03230	Coal Lease	4/4/1973	4/3/1998
3UN-03231	Coal Lease	8/21/1973	8/20/1998
3UN-03232	Coal Lease	8/21/1973	8/20/1998
3UN-03233	Coal Lease	8/21/1973	8/20/1998
3UN-03241	Coal Lease	7/28/1997	6/30/2017
3UN-03242	Surface Lease Agreement	11/27/1995	11/26/2035
3UN-03252	Coal Lease	5/1/2003	4/30/2023
3UN-03253	Surface & Coal Lease Agreement	11/11/2005	11/10/2015
3UN-03800	Coal Lease	4/26/2007	4/25/2037
3UN-03801	Coal Lease	4/26/2007	4/25/2037
3UN-03803	Coal Lease	4/26/2007	4/25/2037
3UN-03804	Lease	9/1/1975	12/31/2045
3UN-03805	Coal Lease	1/1/2018	12/31/2037
3UN-03806	Exploration Contract & Coal Lease	4/2/1973	4/1/2014
3UN-03807	Surface & Coal Lease Agreement	5/16/2016	5/15/2036
3UN-03808	Surface & Coal Lease Agreement	11/1/2016	10/31/2036
3UN-03809	Surface & Coal Lease Agreement	11/1/2016	10/31/2036
3UN-03810	Surface & Coal Lease Agreement	11/2/2016	11/1/2036
3UN-03811	Surface & Coal Lease Agreement	11/3/2016	11/2/2036
3UN-03812	Surface & Coal Lease Agreement	10/31/2016	10/30/2036
3UN-03813	Surface & Coal Lease Agreement	1/4/2017	1/3/2037
3UN-03814	Surface & Coal Lease Agreement	12/29/2016	12/28/2036
3UN-03815	Surface & Coal Lease Agreement	3/2/2017	3/1/2037
3UN-03816	Surface & Coal Lease Agreement	4/19/2017	4/18/2027
3UN-03817	Coal Lease Agreement	6/1/2017	1/29/2013
3UN-03818	Coal Lease Agreement	7/14/2017	7/13/2037
3UN-03819	Coal Lease Agreement	7/18/2017	7/17/2037
3UN-03820	Surface & Coal Lease Agreement	6/19/2018	6/18/2038
3UN-03821	Coal Lease Agreement	6/18/2018	6/17/2038
3UN-03822	Coal Lease Agreement	6/18/2018	6/17/2038
3UN-03823	Coal Lease Agreement	7/3/2018	7/2/2038
3UN-03824	Coal Lease Agreement	9/18/2018	9/17/2038
3UN-03825	Surface Lease Agreement	9/18/2018	9/17/2038
3UN-03826	Surface & Coal Lease Agreement	2/5/2019	2/4/2039
3UN-03827	Surface & Coal Lease Agreement	2/12/2019	2/11/2039
3UN-03828	Surface & Coal Lease Agreement	3/21/2019	3/20/2039
3UN-03829	Coal Lease	11/20/2018	11/19/2048
3UN-03830	Coal Lease	11/20/2018	11/19/2048
3UN-03831	Coal Lease	11/20/2018	11/19/2048

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022


3UN-03832	Coal Lease	11/20/2018	11/19/2048
3UN-03833	Coal Lease Agreement	1/9/2020	1/8/2050
3UN-03835	Surface & Coal Lease Agreement	7/20/2020	7/19/2040
3UN-03836	Surface & Coal Lease Agreement	4/22/2020	4/21/2040
3UN-03837	Surface & Coal Lease Agreement	4/14/2020	4/13/2040
3UN-03838	Surface Lease Agreement	12/31/2019	12/30/2039
3UN-03839	Coal Lease	6/12/2020	6/11/2050
3UN-03840	Coal Lease Agreement	8/26/2020	8/25/2040
3UN-03841	Coal Lease Agreement	8/26/2020	8/25/2040
3UN-03842	Coal Lease Agreement	8/27/2020	8/26/2040
3UN-03843	Surface Lease Agreement	12/16/2020	12/15/2040
3UN-03844	Coal Lease Agreement	9/9/2020	9/8/2040
3UN-03845	Coal Lease Agreement	11/28/2020	11/27/2040
3UN-03846	Coal Lease Agreement	11/30/2020	11/29/2040
3UN-03847	Coal Lease Agreement	12/2/2020	12/1/2040
3UN-03848	Coal Lease Agreement	12/2/2020	12/1/2040
3UN-03849	Coal Lease Agreement	12/3/2020	12/2/2040
3UN-03850	Coal Lease Agreement	12/3/2020	12/2/2040
3UN-03851	Coal Lease Agreement	12/5/2020	12/4/2040
3UN-03852	Coal Lease Agreement	12/7/2020	12/6/2040
3UN-03853	Coal Lease Agreement	12/12/2020	12/11/2040
3UN-03854	Coal Lease Agreement	12/16/2020	12/15/2040
3UN-03855	Coal Lease Agreement	1/5/2021	1/4/2041
3UN-03856	Coal Lease Agreement	8/19/2021	8/18/2041
3UN-03857	Coal Lease Agreement	8/24/2021	8/23/2041

Table 3.2 IDENTIFICATION OF ACQUISITIONS


Agreement Id	Agreement Type	Agreement Date	Agreement Expiration Date
3-FKC001	Warranty Deed	8/19/1985	12/31/2099
3-FKC002	Warranty Deed	6/11/1987	12/31/2099
3-FKC003	Warranty Deed	9/16/1988	12/31/2099
3-FKC004	Warranty Deed	12/13/1991	12/31/2099
3-FKC005	Mineral Deed	2/19/1993	12/31/2099
3-FKC006	Mineral Deed	10/25/1993	12/31/2099
3-FKC007	Mineral Deed	1/3/1994	12/31/2099
3-FKC008	Warranty Deed	7/12/1994	12/31/2099
3-FKC009	Warranty Deed	7/15/1996	12/31/2099
3-FKC010	Mineral Deed	1/8/1998	12/31/2099
3-FKC011	Mineral Deed	1/26/1999	12/31/2099
3-FKC012	Warranty Deed	2/24/1999	12/31/2099
3-FKC013	Warranty Deed	11/8/2000	12/31/2099
3-FKC014	Mineral Deed	2/22/2006	2/21/2105
3-FKS001	Warranty Deed	10/6/1975	12/31/2099
3-FKS002	Warranty Deed	8/12/1975	12/31/2099
3-FKS003	Warranty Deed	8/29/1975	12/31/2099

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022


3-FKS004	Warranty Deed	8/29/1975	12/31/2099
3-FKS005	Warranty Deed	10/6/1975	12/31/2099
3-FKS006	Warranty Deed	10/6/1975	12/31/2099
3-FKS007	Warranty Deed	10/6/1975	12/31/2099
3-FKS008	Warranty Deed	10/6/1975	12/31/2099
3-FKS009	Warranty Deed	10/6/1975	12/31/2099
3-FKS010	Warranty Deed	8/4/1976	12/31/2099
3-FKS011	Warranty Deed	4/18/1985	12/31/2099
3-FKS012	Warranty Deed	5/5/1980	12/31/2099
3-FKS013	Warranty Deed	6/20/1980	12/31/2099
3-FKS014	Warranty Deed	7/29/1980	12/31/2099
3-FKS015	Warranty Deed	10/31/1980	12/31/2099
3-FKS016	Warranty Deed	10/31/1980	12/31/2099
3-FKS018	Warranty Deed	2/10/1981	12/31/2099
3-FKS019	Warranty Deed	4/27/1981	12/31/2099
3-FKS020	Warranty Deed	6/29/1981	12/31/2099
3-FKS022	Warranty Deed	3/15/1982	12/31/2099
3-FKS024	Warranty Deed	6/29/1983	12/31/2099
3-FKS025	Warranty Deed	1/28/1986	12/31/2099
3-FKS027	Warranty Deed	5/21/1984	12/31/2099
3-FKS028	Warranty Deed	7/20/1984	12/31/2099
3-FKS029	Warranty Deed	7/25/1984	12/31/2099
3-FKS030	Warranty Deed	8/31/1984	12/31/2099
3-FKS031	Warranty Deed	11/2/1984	12/31/2099
3-FKS032	Personal Representative Deed	11/24/1984	12/31/2099
3-FKS033	Warranty Deed	11/26/1984	12/31/2099
3-FKS034	Warranty Deed	11/30/1984	12/31/2099
3-FKS035	Warranty Deed	2/11/1985	12/31/2099
3-FKS036	Warranty Deed	2/15/1985	12/31/2099
3-FKS037	Warranty Deed	5/31/1985	12/31/2099
3-FKS038	Warranty Deed	8/8/1985	12/31/2099
3-FKS039	Warranty Deed	8/19/1985	12/31/2099
3-FKS040	Warranty Deed	12/3/1985	12/31/2099
3-FKS041	Warranty Deed	12/30/1985	12/31/2099
3-FKS042	Warranty Deed	12/30/1985	12/31/2099
3-FKS044	Warranty Deed	4/17/1986	12/31/2099
3-FKS045	Warranty Deed	6/12/1986	12/31/2099
3-FKS046	Warranty Deed	7/28/1986	12/31/2099
3-FKS047	Warranty Deed	12/19/1986	12/31/2099
3-FKS048	Warranty Deed	12/30/1986	12/31/2099
3-FKS049	Warranty Deed	6/11/1987	12/31/2099
3-FKS050	Warranty Deed	9/9/1987	12/31/2099
3-FKS051	Warranty Deed	10/30/1987	12/31/2099
3-FKS052	Warranty Deed	10/30/1987	12/31/2099
3-FKS053	Warranty Deed	1/9/1988	12/31/2099
3-FKS054	Warranty Deed	9/16/1988	12/31/2099
3-FKS055	Warranty Deed	9/16/1988	12/31/2099

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022


3-FKS056	Warranty Deed	8/26/1989	12/31/2099
3-FKS057	Warranty Deed	8/30/1989	12/31/2099
3-FKS058	Warranty Deed	7/13/1990	12/31/2099
3-FKS059	Warranty Deed	7/13/1990	12/31/2099
3-FKS060	Warranty Deed	12/13/1991	12/31/2099
3-FKS061	Warranty Deed	12/19/1991	12/31/2099
3-FKS063	Warranty Deed	9/17/1992	12/31/2099
3-FKS064	Warranty Deed	9/17/1992	12/31/2099
3-FKS066	Warranty Deed	10/12/1993	12/31/2099
3-FKS067	Warranty Deed	10/12/1993	12/31/2099
3-FKS068	Warranty Deed	12/31/1993	12/31/2099
3-FKS069	Warranty Deed	7/12/1994	12/31/2099
3-FKS070	Warranty Deed	10/22/1994	12/31/2099
3-FKS071	Warranty Deed	11/16/1994	12/31/2099
3-FKS072	Warranty Deed	12/22/1994	12/31/2099
3-FKS073	Warranty Deed	1/9/1995	12/31/2099
3-FKS074	Warranty Deed	1/9/1995	12/31/2099
3-FKS075	Warranty Deed	1/9/1995	12/31/2099
3-FKS076	Warranty Deed	1/9/1995	12/31/2099
3-FKS077	Warranty Deed	3/28/1995	12/31/2099
3-FKS082	Warranty Deed	5/15/1995	12/31/2099
3-FKS083	Warranty Deed	6/16/1995	12/31/2099
3-FKS084	Warranty Deed	7/14/1995	12/31/2099
3-FKS085	Warranty Deed	10/27/1995	12/31/2099
3-FKS086	Warranty Deed	11/15/1995	12/31/2099
3-FKS087	Warranty Deed	11/27/1995	12/31/2099
3-FKS088	Warranty Deed	12/15/1995	12/31/2099
3-FKS089	Warranty Deed	12/12/1995	12/31/2099
3-FKS090	Warranty Deed	2/16/1996	12/31/2099
3-FKS091	Warranty Deed	2/19/1996	12/31/2099
3-FKS093	Warranty Deed	5/15/1996	12/31/2099
3-FKS094	Warranty Deed	6/21/1996	12/31/2099
3-FKS095	Warranty Deed	7/15/1996	12/31/2099
3-FKS096	Warranty Deed	8/9/1996	12/31/2099
3-FKS097	Warranty Deed	8/9/1996	12/31/2099
3-FKS098	Warranty Deed	10/15/1996	12/31/2099
3-FKS099	Warranty Deed	11/27/1996	12/31/2099
3-FKS100	Warranty Deed	3/7/1997	12/31/2099
3-FKS101	Warranty Deed	3/7/1997	12/31/2099
3-FKS102	Warranty Deed	3/7/1997	12/31/2099
3-FKS103	Warranty Deed	3/7/1997	12/31/2099
3-FKS104	Warranty Deed	3/5/1997	12/31/2099
3-FKS105	Warranty Deed	1/7/1999	12/31/2099
3-FKS106	Warranty Deed	7/7/1998	12/31/2099
3-FKS107	Warranty Deed	8/14/1997	12/31/2099
3-FKS108	Warranty Deed	2/29/2000	12/31/2099
3-FKS109	Warranty Deed	1/23/2001	12/31/2099

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022


3-FKS110	Warranty Deed	12/23/1999	12/31/2099
3-FKS111	Warranty Deed	2/24/1999	12/31/2099
3-FKS112	Warranty Deed	11/24/1999	12/31/2099
3-FKS113	Warranty Deed	3/14/2000	12/31/2099
3-FKS114	Warranty Deed	5/10/2000	12/31/2099
3-FKS115	Warranty Deed	11/8/2000	12/31/2099
3-FKS116	Warranty Deed	8/15/2001	12/31/2099
3-FKS117	Warranty Deed	8/15/2001	12/31/2099
3-FKS118	Warranty Deed	9/10/2001	12/31/2099
3-FKS119	Warranty Deed	1/14/2002	12/31/2099
3-FKS120	Warranty Deed	1/17/2002	12/31/2099
3-FKS121	Warranty Deed	2/19/2002	12/31/2099
3-FKS122	Warranty Deed	2/19/2002	12/31/2099
3-FKS123	Warranty Deed	4/18/2002	12/31/2099
3-FKS124	Warranty Deed	6/13/2002	12/31/2099
3-FKS125	Warranty Deed	12/17/2002	12/31/2099
3-FKS126	Warranty Deed	6/23/2003	12/31/2099
3-FKS127	Warranty Deed	2/20/2004	12/31/2099
3-FKS128	Warranty Deed	10/10/2003	12/31/2099
3-FKS129	Warranty Deed	4/10/2003	12/31/2099
3-FKS130	Warranty Deed	3/19/2004	12/31/2099
3-FKS131	Deed of Personal Representative	8/23/2004	12/31/2099
3-FKS132	Warranty Deed	11/10/2004	12/31/2099
3-FKS134	Warranty Deed	8/1/2006	12/31/2099
3-FKS135	Warranty Deed	4/29/2005	12/31/2099
3-FKS136	Warranty Deed	5/16/2006	12/31/2099
3-FKS137	Warranty Deed	10/2/2006	12/31/2099
3-FKS138	Warranty Deed	9/29/2006	12/31/2099
3-FKS139	Warranty Deed	8/21/2006	12/31/2099
3-FKS140	Warranty Deed	9/29/2006	12/31/2099
3-FKS141	Quit Claim Deed	12/6/2005	12/31/2099
3-FKS142	Warranty Deed	5/19/2006	12/31/2099
3-FKS143	Warranty Deed	7/17/2006	12/31/2099
3-FKS144	Warranty Deed	7/18/2006	12/31/2099
3-FKS145	Trustee's Deed	9/1/2006	12/31/2099
3-FKS146	Warranty Deed	12/5/2006	12/31/2099
3-FKS147	Warranty Deed	1/24/2007	12/31/2099
3-FKS148	Warranty Deed	3/9/2007	12/31/2099
3-FKS149	Warranty Deed	3/20/2007	12/31/2099
3-FKS150	Warranty Deed	3/20/2007	12/31/2099
3-FKS151	Warranty Deed	6/15/2007	12/31/2099
3-FKS152	Warranty Deed	7/31/2007	12/31/2099
3-FKS153	Warranty Deed	8/31/2007	12/31/2099
3-FKS154	Warranty Deed	2/8/2008	12/31/2099
3-FKS155	Warranty Deed	1/23/2008	12/31/2099
3-FKS156	Warranty Deed	1/23/2008	12/31/2099
3-FKS157	Warranty Deed	4/25/2008	12/31/2099

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022


3-FKS158	Warranty Deed	6/5/2008	12/31/2099
3-FKS159	Warranty Deed	6/16/2008	12/31/2099
3-FKS160	Warranty Deed	6/17/2008	12/31/2099
3-FKS161	Warranty Deed	1/23/2009	12/31/2099
3-FKS162	Warranty Deed	6/4/2009	12/31/2099
3-FKS163	Warranty Deed	12/17/2009	12/31/2099
3-FKS164	Warranty Deed	4/8/2010	12/31/2099
3-FKS165	Warranty Deed	5/13/2010	12/31/2099
3-FKS166	Warranty Deed	5/12/2010	12/31/2099
3-FKS167	Warranty Deed	5/12/2010	12/31/2099
3-FKS168	Warranty Deed	10/6/2010	12/31/2099
3-FKS169	Warranty Deed	11/1/2010	12/31/2099
3-FKS170	Warranty Deed	11/1/2010	12/31/2099
3-FKS171	Warranty Deed	10/29/2010	12/31/2099
3-FKS172	Warranty Deed	11/24/2010	12/31/2099
3-FKS173	Warranty Deed	12/8/2010	12/31/2099
3-FKS174	Warranty Deed	12/21/2010	12/31/2099
3-FKS175	Warranty Deed	1/27/2011	12/31/2099
3-FKS176	Warranty Deed	1/27/2011	12/31/2099
3-FKS177	Warranty Deed	4/1/2011	12/31/2099
3-FKS178	Warranty Deed	5/20/2011	12/31/2099
3-FKS179	Warranty Deed	5/15/2011	12/31/2099
3-FKS180	Warranty Deed	9/2/2011	12/31/2099
3-FKS181	Warranty Deed	12/16/2011	12/31/2099
3-FKS182	Warranty Deed	12/27/2011	12/31/2099
3-FKS183	Warranty Deed	3/23/2012	12/31/2099
3-FKS184	Warranty Deed	8/31/2012	12/31/2099
3-FKS185	Warranty Deed	12/18/2012	12/31/2099
3-FKS186	Warranty Deed	4/9/2013	12/31/2099
3-FKS187	Warranty Deed	7/8/2014	12/31/2099
3-FKS188	Warranty Deed	8/15/2014	12/31/2099
3-FKS189	Warranty Deed	10/21/2014	12/31/2999
3-FKS190	Warranty Deed	12/23/2014	12/31/2099
3-FKS191	Warranty Deed	5/5/2015	12/31/2099
3-FKS192	Warranty Deed	1/6/2015	12/31/2099
3-FKS193	Warranty Deed	1/30/2015	12/31/2099
3-FKS194	Warranty Deed	8/5/2015	12/31/2099
3-FKS195	Warranty Deed	8/5/2015	12/31/2099
3-FKS196	Warranty Deed	11/4/2015	12/31/2099
3-FKS197	Warranty Deed	12/22/2015	12/31/2099
3-FKS198	Warranty Deed	12/21/2015	12/31/2099
3-FKS199	Warranty Deed	1/11/2016	12/31/2099
3-FKS200	Warranty Deed	5/13/2016	12/31/2099
3-FKS201	Warranty Deed	11/29/2016	12/31/2099
3-FKS202	Warranty Deed	12/8/2017	12/31/2099
3-FKS203	Warranty Deed	12/28/2018	12/31/2099
3-FKS204	Warranty Deed	2/14/2019	12/31/2099

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022


3-FKS205	Warranty Deed	6/5/2019	12/31/2099
3-FKS206	Warranty Deed	11/18/2019	12/31/2099
3-FKS207	Warranty Deed	12/20/2019	12/31/2099
3-FKS208	Warranty Deed	3/9/2020	12/31/2099
3-FKS209	Warranty Deed	1/30/2020	12/31/2099

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022

3.4 SIGNIFICANT ENCUMBRANCES TO THE PROPERTY

The Falkirk Mine currently has no significant encumbrances to the property. No Notice of Violations (NOVs) have been issued at the Falkirk Mine in the past three years. Permitting requirements are discussed in Section 17.0 of this TRS.

3.5 SIGNIFICANT FACTORS AND RISKS

Falkirk has not identified any significant risks that may affect the right or ability to perform work on the property. Each lease and special obligations for each lease are reviewed on an annual basis to ensure there is no lapse in lease continuation or payments. If a lease expires or a payment lapses, the landowner may choose not to release this property for mining.

3.6 REGISTRANT ROYALTIES AND INTERESTS

Discussed in Section 3.3 of this TRS.

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022

4.0 ACCESSIBILITY, CLIMATE, LOCAL RESOURCES, INFRASTRUCTURE, AND PHYSIOGRAPHY

4.1 PHYSIOGRAPHY, TOPOGRAPHY AND VEGETATION

The Falkirk Mine, located in McLean County, North Dakota (ND) occurs in the physiographic region of North Dakota known as the “Coteau Slope” and is dominated by landforms that are primarily glacial in origin. Glacial sediments or drift belonging to the Coleharbor Formation were deposited over the land comprising this area during the Wisconsin Age. The maximum relief of the Falkirk Mine is approximately 360 feet (msl), with the elevation ranging from 1720 feet (msl) in the Missouri River Watershed drainage to the south to nearly 2080 feet (msl) in the Lake Audubon Watershed drainage to the north. Topographic features of the Falkirk Mine are shown on Figure 4.1 in the Supplemental Figures Attachment (Pre-mining Topography).

The Soil Survey of McLean County indicates that 95 percent of the acreage is in farms and the land-use is approximately 73 percent cultivated cropland. Vegetative baseline studies of the permitted areas further indicate the prominent vegetation of the Falkirk Mine to be cropland Other vegetative designations include native grassland, tame pastureland, shelterbelts, fish and wildlife habitat and wetlands.

4.2 ACCESSIBILITY

Local access to the Falkirk Mine is by way of Highway 83 between Washburn, ND and Underwood, ND. The mine access road, 1st Street SW, connects to Highway 83 and is approximately 2 miles long.

Travel to the Falkirk Mine by air is possible using the Bismarck Airport in Bismarck, ND, approximately 55 miles south of the mine, and then using ground transportation, traveling via Highway 83.

The main railway systems near the Falkirk Mine are Canadian Pacific, BNSF, and Dakota Missouri Valley & Western (DMVW). DMVW crosses through the Falkirk Mine Reserve.

4.3 CLIMATE

The climate at the Falkirk Mine can be characterized as continental with a semi-arid moisture regime. The region receives about 16 inches of moisture annually, 75% of which occurs as rain during the spring, summer and fall months, with the remaining 25% occurring as snow during the winter months. The average length of the growing season is about 130 days. Temperatures throughout the region range from a mean of 7º F. during January, which is the coldest month of the year, to a mean of 69º F. during July, which is typically the warmest month of the year.

4.4 LOCAL RESOURCES AND INFRASTRUCTURE

The towns of Washburn and Underwood are within a 10-mile radius of the Falkirk Mine, the towns of the Riverdale and Turtle Lake are within a 25-mile radius and the towns of Bismarck, Mandan and Minot are within a 60-mile radius. These communities provide a vast portion of the employment base at the Falkirk Mine and the CCSPP.

The Falkirk Mine sources power for mine office facilities and operations from the CCSPP. Water for the mine main office facilities also comes from the CCSPP, but Falkirk’s East shift change building receives water from McLean-Sheridan Rural Water. Fuel for equipment is supplied by Dale’s Petroleum Services, Inc., Enerbase Cooperative Services, Farstad Oil, Inc., and Marthon Petoleum Cooperation. These companies are located in Bismarck, Fargo and Minot, ND. The Falkirk Mine has all supporting infrastructure for mining operations. See Section 15.0 for further detail pertaining to the mine specific infrastructure.

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5.0 HISTORY OF THE PROPERTY

The general information provided below is summarized in the Falkirk Mine North Dakota State Mining Permits. Insert permit information

5.1 PREVIOUS OPERATIONS

The Falkirk Mining Company is the owner and operator of the Falkirk Mine.

Construction of the Falkirk Mine began in 1975 and deliveries began in October 1978 to the CCSPP owned by Great River Energy.

There were several small underground mines and one small surface mine, all operated and closed in the mid 1900’s, on Falkirk Mine property.

5.2 EXPLORATION AND DEVELOPMENT HISTORY

The Falkirk Mine’s initial reserve base began with a coal field known as the Underwood Coalfield. The Underwood Coalfield is roughly a circular deposit ranging from 6 to 8 miles in diameter with the City of Underwood near the center. The Paleocene lignite deposits of the field are bounded by buried Pleistocene glacial channels.

The presence of coal around the City of Underwood has been known since the early pioneer days when farmers dug lignite by hand from erosional banks. Later, small to medium underground mines developed to exploit the resource. The last of the underground mines closed in the early 1950s.

Combined with these old coal mines, there were numerous groundwater wells reporting coal of some thickness. In fact, the coal seams of the Underwood Coalfield are local groundwater aquifers. This lead to government and university studies that began to define the lignite coal geology of the area.

In the late 1960s and early 1970s, The North American Coal Corporation conducted exploration drilling programs to define the lignite resources in the area. These drillholes were mostly rotary holes drilled with air/mist, while some were drilled with mud. These early holes were very widely spaced; however, the data was sufficient to show the existence of a very large lignite coal reserve.

Based on the early drilling data, The North American Coal Corporation developed a contract with a utility to build a mine adjacent to a new power plant on the site. The power plant and mine facilities were located on the southern glacial channel so as to not cover up any of the coal reserve. Extensive drilling and coring programs were also initiated in 1974 and 1975 to more accurately define the coal resources of the area. In general, these drill holes were on a 2-mile spacing; with some further and some closer apart.

The 1974 and 1975 drilling and coring data was used to determine the initial mine plan and was the basis for a 20-year cost of coal study. With this engineering study, an area was defined for a state permit application; requiring additional drilling and analysis of overburden and coals. This permit drilling was conducting in 1976 and 1977. The 1977 drilling also began to fill in the drill hole spacings in future mining areas. Since then, the Falkirk Mine has conducted annual drilling programs with 3 primary objectives:

1.Drill and core on the required 40-acre (1,320 foot) spacing for mining permit applications. Mining permits have a maximum term of 5-years.

2.Drill and core areas to help improve mining efficiency. These areas include buried sub-crop lines, weathered coal areas, and high sulfur and/or sodium areas.

3.Continue to reduce the grid spacing in future mine areas to further define the coal.

Throughout the 50+ year history of the Falkirk Mine’s coalfield, The North American Coal Corporation has always used policies, protocols and procedures to ensure the accuracy and integrity of the drilling and coring data. Experienced geologists have always been on the drill rigs or supervising the engineers and/or students on the drill rigs. However, technologies and understandings change. Prior to 1976, the Falkirk Mine did not have a survey grid established. Hence, drill hole locations and elevations were read from USGS topographic quadrangle maps. Also, prior to 1975, geophysical logging on shallow coal exploration holes was not a common practice. This caused errors and deviations in locations, elevations and depths, especially as compared to more modern methods with higher levels of control. Consequently, all drilling data prior to 1976 has been deleted from Falkirk Mine’s databases and is no longer used for modeling and reserve-resource estimates. It was good information at the time, but it has all been replaced by more accurate and controlled data. In addition, Falkirk has developed drilling, logging, and laboratory

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analysis contracts to help control data accuracy and integrity. Internal documents have also been developed that spell out step by step details of how drilling and sampling will be conducted.

Construction of the Falkirk Mine began in 1975. Coal removal began in 1978 and the CCSPP (2-units , each at 550 MW’s) started Unit #1; Unit #2 started in 1979. The North American Coal Corporation made a lease trade with the Consolidated Coal Company (Consol) in the mid-1980s. North American gave Consol underground coal reserves in Ohio and received coal reserves in North Dakota. These North Dakota coal reserves lie immediately south-southwest of the Underwood Coal Field.

The coal reserves from Consol were incorporated into the Falkirk Mine and became known as the Riverdale Coalfield. Falkirk did receive copies of all of Consol’s drilling data in the area. However, it was lacking in survey accuracy, geophysical logging, as well as known control systems. Thus, beginning in 1989, the Falkirk Mine began a drilling program to redrill all of Consol’s old drill holes and to begin completing drill hole on grids to support mining permit applications and future mine plans. Initial mining of the Riverdale Coalfield began in 1994 .

6.0 GEOLOGICAL SETTING, MINERALIZATION AND DEPOSIT

6.1 REGIONAL AND LOCAL GEOLOGY

The Falkirk Mine is located in the Sentinel Butte Formation of the Fort Union Group (Figure 6.1) which is one of the most prolific lignite-bearing stratum in the state. Substantial information has been gathered during exploration drilling programs within the region since the late 1960s. These data were the fundamental tools used in characterizing substrate composition, geometry, and structure of the Falkirk Mine lignite deposit prior to mining. Understanding of the local geology has continued with regular, fill-in drilling exploration programs and mining operations.

Figure 6.1. Geologic and Topographic Bedrock Map of North Dakota (Bluemle, 1983)

The coal bearing stratigraphy of North Dakota is depicted on Figure 6.2.

Figure 6.2. Coal Bearing Stratigraphic Column of North Dakota (Murphy, et al, 2009).

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Structurally, the area is located on the east flank of the Williston Basin, an intercratonic basin containing a thick sequence of sedimentary rocks. The basin dominates the structural characteristics of much of North Dakota, northwestern South Dakota, eastern Montana, and parts of Manitoba and Saskatchewan. The center of the basin is located near the city of Williston, North Dakota, approximately one hundred twenty-five (125) miles northwest of the reserve. The Williston Basin contains sedimentary rocks of every geologic period from the Cambrian (600 million to 500 million years ago) through the Tertiary (65 million to 3 million years ago).

The stratigraphy of the reserve area has been influenced by the deposition from epicontinental seas and by basinal subsidence. The history of the extensive deposition and subsidence can be divided conveniently into the sequence subdivisions (Sauk, Tippecanoe, Kaskaskia, Absaroka, and Zuni) based on the major unconformities within the preserved section. These epicontinental seas deposited a wide range of sedimentary rocks in the basin, mainly carbonates, evaporites, and shales. Regression of the Zuni Sea and successive episodes of the Laramide Orogeny resulted in the deposition of a continuum of marine and terrestrial (Late Cretaceous - Early Tertiary) sedimentary rocks. The terrestrial strata consist of a sequence of sediment transported eastward from western source areas by Early Tertiary fluvial systems. It is doubtful that positive structures (with the exception of the Black Hills uplift) capable of exerting major influence on the dispersal of sediments were present on the craton, but negative structures did influence sediment accumulation and preservation.

The economically minable coals in the reserve occur in the Sentinel Butte Formation (Paleocene) and the Bullion Creek Formation (Paleocene) and are unconformably overlain by the Coleharbor Formation (Quaternary). The Sentinel Butte Formation conformably overlies the Bullion Creek Formation.Paleocene deposition was initiated by an influx of coarse sediment dispersed eastward and southeastward, in deltaic fashion, across early Bullion Creek swamps. The paleoslope appears to have been variable, both in magnitude and in direction, and reflects Paleocene tectonism to the west and northwest. The elevation of western North Dakota, relative to base level, increased during Sentinel Butte time and probably reflects increased deposition to basinal subsidence. After the close of the Oligocene Epoch (26 million years ago), erosion was the predominant process affecting the existing landscape. This was a time of development of an integrated drainage system over much of the area. The topography of the area in the early Pleistocene was probably similar to the present topography in areas of thin glacial drift.

The area was affected by all four (4) of the major Pleistocene (3 million to 10 thousand years ago) glaciations. Each glacial episode modified the previous landscape through erosional and depositional processes. The area was most recently glaciated during the Wisconsinan stage. During early Wisconsinan (50 thousand years ago) time, the Napolean ice advanced across the area depositing drift on a rolling topography that was mainly bedrock with only a thin veneer of pre-Wisconsinan drift in the topographic lows. Most of the pre-Wisconsinan drift had been removed by erosional processes by the time Napolean ice advanced across the area. The present topography of the general area is mainly stream-dissected bedrock with a veneer of glacial sediments. A few buried glacial meltwater channels are also present.

The reserve area is situated on a glacially modified upland drainage divide of relatively low relief. The reserve is defined on the south and west by the present day Missouri River Valley. The northern and eastern extents of the field are defined by pre-glacial channels that have subsequently been modified by glacial and interglacial activity. The valley to the east is incised by a glacial meltwater channel (Coal Lake Coulee). The valley bisecting the reserve, whose surface is now occupied by the Weller Slough Complex, appears to have been a main tributary of the pre-glacial Knife River. This bisecting valley divides the reserve into two coalfields, locally referred to as the Underwood Coal Field to the north and the Riverdale Coal Field to the south.

The Bullion Creek Formation (Paleocene) underlies much of the reserve area. The Sentinel Butte Formation (Paleocene) conformably overlies the Bullion Creek Formation. Lithologically, the two formations are very similar. Interbedded silts and clays that occur in beds that range in thickness from less than one (1) foot to tens of feet make up about sixty) to eighty percent of the sediment of the Bullion Creek and Sentinel Butte Formations. From fifteen

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to thirty-five percent of the sediment making up these formations consists of silty, fine-grained to medium-grained sand in beds that range in thickness from one-half (½) to one hundred feet. Lignite is a minor constituent, generally comprising less than five percent of the formations. The lignite occurs in beds ranging in thickness from less than one-tenth) foot to about fifteen feet locally. The Coleharbor Formation (Pleistocene) unconformably overlies the Sentinel Butte and Bullion Creek Formations. It includes all of the unconsolidated sediments resulting from deposition during glacial and interglacial periods. Lithologic types include gravel, sand, silt, clay, and till. The Oahe Formation (Holocene) occurs as a thin veneer of eolian silt sized sediment that blankets upland surfaces in the area. The modified glacial channels that delineate the reserve limits are in-filled with sediments of the Coleharbor Formation. The channel fill systems contain a complex of interbedded glaciofluvial gravels, sands, silts, and clays overlain by till. The coarser gravel and sand beds are generally limited to near the bottom of the channel fill.

The general stratigraphic sequence in the upland portions of the reserve area (Sentinel Butte Formation) consists of till, silty sands and clayey silts, main Hagel (Hagel A) lignite bed, silty clay, lower lignite of the Hagel lignite interval (Hagel B), and silty clays. Both the Hagel A Bed and the Hagel B Bed are split by clay partings in portions of the reserve; although the two beds are not split in the same areas. Where the beds have partings, the splits are refered to as Hagel A1, Hagel A2, Hagel B1, and Hagel B2. There are thinner beds of lignite above the Hagel bed in some areas. These thin lignite beds are part of the Kinneman Creek seam. The Kinneman Creek in most areas is thin, very weathered, and very high in ash. In areas where it is mineable it can reach up to 3.5 feet thick and is lower in ash. Where the Kinneman Creek is parted, it is refered to as the Upper Kinneman Creek and Lower Kinneman Creek.

Near the contact of the Sentinel Butte and Bullion Creek Formations in a complex of sands and thin (less than one (1) foot ) lignite beds locally referred to as the C Sand and C Seam. As in the Sentinel Butte, the Bullion Creek Formation consists of till, silty sands and clayey silts, main Tavis Creek lignite bed, silty clay, and silty clays. The Tavis Creek Bed is split by a clay parting in portions of the reserve. Where the bed has a parting, the splits are referred to as Upper Tavis Creek and Lower Tavis Creek. There are thin lignite beds immediately above and/or below the Tavis Creek in many areas. The first of these thinner seams below the Tavis Creek bed is the Coal Lake Coulee seam. The Coal Lake Coulee seam parted in areas of the reserve and the splits are refered to as the Upper Coal Lake Coulee and the Lower Coal Lake Coulee. Below the Coal Lake Coulee seam, there is a repeating sequence of silty to sand clays with generally thin lignite beds.

Geologic cross-sections A-A', B-B', C-C', M-M', and N-N' (Figure 6.3 in the Supplemental Figures Attachment through the Underwood Reserve, were constructed using data compiled from existing drill holes to illustrate the subsurface relationships of the above mentioned stratigraphic units. The compiled data is based on the drill hole data but is in the form of 3D grid files (a geologic model)

Geologic cross-sections A-A', B-B', C-C', D-D', E-E', F-F' and G-G' (Figure 6.4 in the Supplemental Figures Attachment) through the Riverdale Reserve, were constructed using data compiled from existing drill holes to illustrate the subsurface relationships of the above mentioned stratigraphic units. The compiled data is based on the drill hole data but is in the form of 3D grid files (a geologic model).

7.0 EXPLORATION

No exploration work other than drilling and associated geophysical logging has been conducted at the Falkirk Mine. Geophysical logging is discussed with drilling in Section 7.1 of this TRS.

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7.1 DRILLING EXPLORATION

Data collected during drilling exploration programs at the Falkirk Mine is the sole information available for modeling the lignite deposit for the determination of Mineral Resources. Following coal industry standards, the sampling method used by the Falkirk Mine for modeling quality of the lignite deposit is exclusively core drilling. The Falkirk Mine lignite deposits are evaluated on a seam by seam basis. Drilling exploration data including geologic lithologies, qualities, and hole locations have been compiled in an electronic, geologic database. The information below summarizes the related drilling records.

7.1.1 DRILLING METHODS

Drilling exploration programs conducted at the Falkirk Mine have comprised largely of rotary air/mist or mud drilling methods. For the purpose of this discussion, senior geologist and field geologist refer to qualified representatives of Falkirk and/or NACoal. Historically, Falkirk has contracted independent drilling services and geophysical logging services. Drill holes completed at the Falkirk Mine are vertical in orientation and have been broken into four categories which are described below. A drill hole collar location map for the Falkirk Mine is presented in Figure 7.1 in the Supplemental Figures Attachment

Exploratory drill holes, also referred to as pilot holes, typically range in size 5.0 inches (outer hole diameter, od) and terminate at a minimum of 12-feet below the lowest targeted lignite seam as specified by the senior geologist to allow for proper geophysical logging. Cuttings are recovered by the contracted driller on a 5-foot interval and are described by the field or senior geologist. All pilot holes are geophyscially logged for natural gamma, density, caliper, and resistivity responses.

Coal core holes to collect samples for quality assessment are advanced next to pilot holes at specified locations. Core holes are typically 5.6-inches (outer diameter, od) to the point where coring starts, then through coring 4.6-inches (od) with a respective sample diameter of 3.0-inches (od). Samples are collected with a split double core barrel. Coring intervals are determined by the field geologist and reviewed by the senior geologist based on the pilot hole’s geophysical log and cuttings descriptions. Core holes terminate one to two feet below the lowest targeted lignite seam. 90-percent coal core recovery is required such that the field or senior geologist logging the sample can clearly define the roof and floor of the lignite seam (see Section 8.0 for discussion on sample preparation). It is standard practice to only geophysically log the adjacent pilot hole because of its close proximity to the core hole. In unique cases, the core hole may be geophysical logged if there appears to be a discrpency in thickness or elevation between the rotary hole and core hole. with the field logs and quality data for determination of lithologic intervals to be modeled.

Overburden core holes are drilled following the same protocol to the coal cores as described above with the addition of collecting overburden, interburden and underburden samples at five foot intervals. These samples bagged and sent to the lab for textural and geochemacial in addition to lignite, which are shipped to a separate soil lab for geochemical analysis. Data specific to the coal cores collected during these overburden core sampling programs have been reviewed by the QP for inclusion in the geological model.

The fourth, and final, category of drill holes comprise of geotechnical holes and monitoring wells which have been geophysically logged and extend through multiple coal seams. These drill holes follow the parameters outlined for pilot holes and available data has been reviewed by the QP.

7.1.2 GENERAL DRILLING PROCEDURES

Details may vary with each exploration program, however general procedures for drilling at Falkirk Mine include:

–Identification of land control; acquire drilling leases for properties not owned or previously leased.

–Site preparation.

–Rotary wash drilling by an independent drilling contractor; cuttings are collected every 5-feet to final depth.

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–Field geologist logs description of cuttings including depth, texture, general color.

–Independent contractor geophysically logs drill hole for natural gamma, density, caliper, and resistivity.

–Field geologist reviews geophysical log.

–Hole determined complete, and abandoned by independent drilling contractor in accordance with regulatory requirements.

–Survey drill hole collar location.

To continue with a coal core hole:

–Coring intervals determined by field or senior geologist from pilot hole geophysical log.

–Coal core drilling by an independent drilling contractor.

–Core extracted from barrel by independent drilling contractor and placed in logging tray.

–Field geologist cleans core sample of drilling mud, measures the core length and identifies the roof and floor. If recovery is less than 90-percent, independent drilling contractor may attempt to retrieve the remaining core from the current hole. If no success, the core run interval will be “re-cored” as an additional core hole.

–Field geologist logs the core including depths, fractures, texture, color, and characteristics of the lignite.

–Field geologist double bags and double tags sample.

–Once all intervals are cored, independent contractor geophysically logs drill hole.

–Field geologist reviews geophysical log.

–Hole determined complete, and abandoned by independent drilling contractor in accordance with regulatory requirements.

–Survey drill hole collar location.

Additional drilling tasks include:

–Maintaining daily drilling report and record of collected samples.

–Proper storage of lignite core samples in secure location of the mine office and transfer to the warehouse to prepare for shipment to laboratory.

7.1.3 DRILLING EXPLORATION PROGRAMS

As previously discussed in Section 5.2 of this document, numerous drilling exploration programs have been conducted at the Falkirk Mine. Over 5,400 exploration holes have been drilled. Approximately 2,100 of those holes were sampled for quality assessment.

As a whole, Falkirk plans exploration activities to attain an average 1,320-foot drilling density for the ten-year projection ahead of active mining operations. Physical constraints such as stream buffers can affect the final drilling density. This spacing allows operations to optimize seam blending efforts to ship a steady fuel quality to the power plant. It should be noted for the purpose of Mineral Resource estimations and Life of Mine (LOM) projections, the QP has determined a high to moderate level of confidence in a minimum drill hole spacing of 1,320-feet. This confidence comes from the continuity of the lignite seams including both lithologic and quality characteristics, as well as the ability to compare modeled seam projections to active and historical mining operations.

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7.2 HYDROGEOLOGIC CHARACTERIZATION

7.2.1 GROUNDWATER STUDIES

Falkirk is conducting ground water monitoring over an extensive area. A Ground Water Monitoring Plan (GWMP) was developed for the Underwood and Riverdale Coal fields and implemented at the Falkirk Mine is intended to fulfill the requirements of North Dakota Administrative Code sections 69-05.2-09-12 and 69-05.2-16-14. The purpose behind the design and implementation of the ground water monitoring plan is threefold; investigate and quantify the pre-mining hydrologic conditions of permitted and adjacent areas, monitor impacts on the ground water hydrology of the area due to surface mining operations and climatic conditions, and monitor and quantify post-mining ground water conditions. A sustained program of ground water data collection also serves to substantiate projected impacts to the hydrology of the permit area as outlined in the probable hydrologic consequences section of each permit application.

The current monitoring well inventory for the Falkirk Mine is listed in Section 2.2 (NAFK-8405, NAFK-8705, NAFK-9503 and NAFK-9601) of the Riverdale and Underwood permits, Well Inventory and Monitoring Schedule. This inventory includes active, inactive, and destroyed monitoring wells. Section 2.2 (NAFK-8405, NAFK-8705, NAFK-9503 and NAFK-9601) also lists the frequency at which water levels and water quality samples are taken. In addition to the monitoring schedule, the Completion Details of Monitoring Wells lists the location of the well, top of casing and ground surface elevations, depths to the top and bottom of the well screen, and the stratum in which the monitoring well is located. All available monitoring well installation and construction information is also contained in 2.2 (NAFK-8405, NAFK-8705, NAFK-9503 and NAFK-9601). Information is included for active, inactive, and destroyed wells. As required by NDAC 69-05.2-08-06(1)(d), available lithologic logs, geophysical logs, well construction reports and diagrams, and well completion reports are presented.

Water levels are reported to the North Dakota Public Service Commission quarterly, within 30 days following the close of each quarter. In the event that access to a monitoring well is denied throughout a quarter due to persistent climatic conditions or circumstances beyond Falkirk's control, then documentation to this effect will be submitted with the quarterly monitoring report.

Water quality samples are analyzed, at a minimum, for the parameters required by NDAC 69-05.2-08-06(1)(e). Sample results will be reported to the North Dakota Public Service Commission (NDPSC) annually within 30 days following the fourth calendar quarter. Wells with adequate water production will be sampled after purging, at a minimum, the volume of stale water calculated to exist in the well, or when the water’s measured parameters for pH and electrical conductivity have reached stabilization. Low producing wells will be purged, allowed to recover, and sampled within twenty-four hours of purging. Wells with insufficient water volume to allow for collection of a representative sample will be documented to that effect in the annual groundwater quality report, in addition to any other condition that may prevent a well from being sampled.

The post-mining monitoring well network consists of wells existing in undisturbed areas and wells installed in reclaimed areas to monitor the quality and elevation of groundwater flowing into and out of the reclaimed spoils. Installation of reclamation monitoring wells in reclaimed areas will be accomplished after SPGM respread, preferably after the establishment of a viable vegetative cover. Generally, reclamation monitoring wells will be placed in the vicinity of pre-mining well sites with screened intervals placed in the same strata where possible. The replacement of wells at pre-mining well sites will facilitate pre- and post-mining hydrogeologic comparisons. The reclamation well installations will concentrate on screening the base of the spoils, with additional wells placed in the next lower aquifer. Information from these initial well installations will determine the need for additional installations.

Locations of destroyed and existing ground water monitoring wells, along with certified domestic wells and springs are shown on Figure 7.2 in the Supplemental Figures Attachment, Groundwater Map excerpted from Falkirks’s Groundwater Monitoring Plan. Many of the destroyed wells were once part of the monitoring program and part of the baseline aquifer testing, but were destroyed due to mining operations or due to being no longer needed.

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The major hydrostratigraphic units in the study area consist of glacial till (pebble loam) and glaciofluvial sands and gravels of the Coleharbor Formation; Hagel A Lignite bed (upper split of the Hagel bed), the Hagel B Lignite bed (lower split of the Hagel bed), and the C sand (a sandy-silty zone of stratum below the Hagel B bed) of the Sentinel Butte Formation; and the Tavis Creek Lignite bed, the Coal Lake Coulee Lignite, and the Hensler sand of the Bullion Creek Formation. Above the Hagel bed is a carbonaceous unit that correlates to the Kinneman Creek Lignite bed. Over most of the study area, this unit is primarily carbonaceous clay with thin interbedded lenses of lignite. Locally, the lignite does develop into the dominant lithology and may act as a local aquifer. Because of its usually shallow depth, the Kinneman Creek bed is usually weathered. Within the zone of the C sand there is usually one and sometime several, thin (less than one foot thick) lignite beds locally referred to as the C bed which we currently refer to as the C seam. Below the Tavis Creek bed are additional lignite beds. The first two below the Tavis Creek bed are named the Coal Lake Coulee bed and the Weller Slough bed. There are also sand units below these beds, the most significant being the Hensler sand which lies beneath the Coal lake Coulee bed Strata lying above the Hagel bed are referred to as the Kinneman Creek Interval. Those underlying the Hagel bed but above the Tavis Creek bed are referred to as the Hagel Interval.

Ground water recharge from surface infiltration occurs because of snowmelt and rainfall. Prairie potholes and depressions where surface water accumulates enhance the mechanisms of infiltration into the groundwater system. The quantity of recharge is determined by vertical hydraulic conductivity of the soils, and the depth of the water table. However, the significant aerial extent of the recharge zone is probably the most important factor in determining the volume of water infiltration into the aquifers. Moran and Cherry (1978), in studies performed in the Underwood Coal Field located just north of the Riverdale Coal Field estimated the annual ground water recharge rate for this area of North Dakota to be between 0.86 inches to 1.32 inches. These values of recharge apply to the zones of recharge and cannot be taken as distributed over all of the area. Average aerial depth of ground water recharge measured by Cherry in 1979 rate over a 150-km2 study area was on the order of 1.0 to 4.7 inches per year. The spring of 1979 was the wettest spring of the decade of the 1970's, so the values of recharge rate for 1979 are probably greater than the long-term, average ground water recharge rate (Rehm, et. al. 1980). Geohydrology of the Coleharbor Formation The Coleharbor Formation (Pleistocene) is the shallowest aquifer in the area. It unconformably overlies the Sentinel Butte Formation and includes all of the unconsolidated sediments resulting from deposition during glacial and interglacial periods. Over most of the area, the Coleharbor is a thin formation that locally thickens where it fills valleys in the buried topography. The modified glacial channels that delineate the mining limits north, east, and south of the permit area are in-filled with sediments of the Coleharbor Formation. The channel fill systems contain a complex of interbedded glaciofluvial gravels, sands, silts, and clays. The coarser gravel and sand beds are generally limited to near the bottom of the channel fill.

Groundwater in the Coleharbor Formation accumulates in the discontinuous sand bodies surrounded by clayey sediments. These sand bodies individually can be described as perched aquifers; the sand bodies lack lateral continuity and are generally of limited aerial extent. Consequently, water wells in the Coleharbor Formation typically have very low yields and capacity. They are also very sensitive to changes in precipitation and resultant recharge. Wells in the Coleharbor Formation will react relatively quickly to changes in precipitation: If it rains, the wells produce well, in a drought, the wells have reduced production or even “go dry”. Hydraulic conductivity values from single well response tests average 8.6 feet per day for the Coleharbor channel fill units in the study area (Groenewold, et. al., 1979). The average hydraulic conductivity of the glacial till test is 0.3 feet per day. Some tests indicate that the hydraulic conductivity value of the glacial till could be as low as 10-5 to 10-7 feet per day (Groenewold, et. al., 1979). Pumping tests performed in the central portion of McLean County indicate hydraulic conductivity values of 104 to 6,739 feet per day for the sand and gravel units of the channel fill aquifers (Klausing, 1974). Storage coefficients of the channel fill aquifers obtained from Klausing’s pumping tests range from 0.0001 to 0.00045. One pumping test yielded a specific yield of 0.14. This indicates that the lower sand and gravel strata found in the channel fills are normally confined by the overlying silts and clays.

Stratigraphically, the Hagel A bed is the highest, significant aquifer in the study area. The seam has local undulations that cause variations in the character of this aquifer. In some areas, the Hagel A bed is confined, but in other areas it is under water table conditions. The potentiometric map of the Hagel A bed suggests that water in this aquifer flows radially from surface recharge areas towards the croplines along the Missouri River Valley, the Weller

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Slough Trench, and tributaries of the Coal Lake Coulee. Discharge from the Hagel A bed along some outcrops and near surface subcrops is in the form of springs.

Results from single well response tests completed in Hagel A bed are presented in Section 2.2 (NAFK-8405, NAFK-8705, NAFK-9503 and NAFK-9601).The measured hydraulic conductivity of the Hagel A bed ranges from 0.05 feet per day to 4.6 feet per day. However, some monitoring wells exhibited a hydraulic conductivity that was too high to be measured with response tests.

The Hagel B bed lies below the Hagel A bed. The Hagel B bed is in direct hydraulic connection with the Hagel A bed in a few places. A few areas of the Hagel B bed are unsaturated to dry, but is generally confined. Potentiometric levels of the Hagel B bed are normally lower than those of the Hagel A bed except in a few areas where they are in equilibrium. This difference induces leakage from the Hagel A bed to the Hagel B bed.

The hydraulic conductivity measured in response tests Section 2.2 (NAFK-8405, NAFK-8705, NAFK-9503 and NAFK-9601) ranges from less than 0.01 feet per day to 3.45 feet per day Section 2.2 (NAFK-8405, NAFK-8705, NAFK-9503 and NAFK-9601). Recharge of the Hagel B bed is primarily leakage from the Hagel A bed. Groundwater flow in the Hagel B bed is from the high potentiometric areas to discharge areas along the croplines of the coal seam along the Missouri River Valley, the Weller Slough Trench, and tributaries of the Coal Lake Coulee. Some discharge along crops is in the form of springs.

The C sand is the first aquifer below the Hagel B bed. The C sand is an interval of sandy silts to silty sands; it also typically includes one or more thin lignite beds (locally referred to as the C seam). The C sand is a confined aquifer that lies 20 to 30 feet below the Hagel B bed and 60 feet above the Tavis Creek bed.

The general flow direction in the C sand is from the high potentiometric areas towards the Weller Slough Trench, the Missouri River Valley, and the trench of Coal Lake Coulee. Recharge of the C sand is primarily through leakage from the Hagel B bed. The hydraulic conductivity of the C sand, measured in response tests, ranges from less than 0.01 feet per day to 30 feet per day.

The Tavis Creek bed is a lignite bed that lies 60 to 100 feet below the C sand, under a layer of Sentinel Butte Formation clay. The flow in the Tavis Creek bed takes place under confined conditions. Flow in the Tavis Creek bed is from the Weller Slough toward the Missouri River. Recharge of this aquifer appears to be primarily from lateral flow from North of the study area and from Weller Slough and associated filled trench drainages. Some leakage may occur from overlying aquifers. However, the significant thickness of the overlying clays suggests that this leakage ought to be relatively small. The potentiometric surface of the Tavis Creek bed is lower than that of the C sand. The Weller Slough Trench is a source of recharge for the Tavis Creek bed. It appears to have been a main tributary to the pre-glacial valley of the Knife River (Bluemle, 1971). The Weller Slough Trench consists of coarse sediments within the broad depression of the buried channel (Bluemle, 1971). It is hydraulically connected with Lake Sakakawea.

Recharge of the Weller Slough Trench aquifer is from precipitation, discharge from shallow aquifers, and Lake Sakakawea (Klausing, 1974). The bottom of the Weller Slough Trench aquifer reaches 306 feet in depth in well NDSWC 4034 (Klausing, 1974). At this location, the thickness of the coarse sediments is sixteen feet (Klausing, 1971). Pumping tests performed in the central portion of McLean County indicate hydraulic conductivity values of 104 to 6,739 feet per day for the sand and gravel units of the channel fill aquifers (Klausing, 1974). Storage coefficients of the channel fill aquifers obtained from pumping tests range from 0.0001 to 0.00045. One pumping test yielded a specific yield of 0.14. This indicates that the lower sand and gravel strata found in the channel fills are normally confined by the overlying silts and clays. Single well response tests performed in the Tavis Creek bed yielded hydraulic conductivity values of less than 0.01 feet per day to 18 feet per day.

The Coal Lake Coulee lignite bed is under confined conditions located between 15 and 30 feet below the Tavis Creek bed. Flow direction is similar to the Tavis Creek bed and is from the Weller Slough toward the Missouri River.

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The main source of recharge for the Coal Lake Coulee bed is from the previously discussed Weller Sough Trench and leakage from the overlying Tavis Creek bed.

The hydraulic conductivity of the Coal Lake Coulee bed, measured in response tests ranges from less than 0.01 feet per day to .32 feet per day.

The Hensler sand is the sand unit monitored as the first aquifer below the Coal Lake Coulee bed. It is part of numerous discontinuous sand units within the Bullion Creek Formation that make up an “aquifer zone” rather than a distinct aquifer (Groenewold, et. al., 1979). The Hensler sand is between just a few feet to more than 30 feet below the Coal Lake Coulee. The flow in the Hensler sand takes place under confined conditions and is from the Weller Slough toward the Missouri River

Recharge of this aquifer appears to be primarily from lateral flow from north of the study area and from leakage from overlying aquifers. The potentiometric surface of the Hensler sand is generally lower than that of the Coal Lake Coulee bed. Single well response tests performed in the Hensler sand yielded hydraulic conductivity values of less than 0.03 feet per day to .25 feet per day.

The Hagel A bed water has calcium-magnesium and sodium as dominant cations. Bicarbonate and sulfate anions are present in the water. The water quality data for the Hagel A bed shows that there is not a predominant type of water. Total dissolved solids range from 777 to 4,838 mg/l and averages 2,082 mg/l. The water is generally very hard.

Water of the Hagel B bed exhibits similar characteristics as the Hagel A bed water. Calcium and magnesium cations are slightly less prevalent, with sodium being the dominant cation in over half of the samples. Dominant bicarbonate anion is more common than dominant sulfate anion type. The water quality data for the Hagel B bed indicates that water type of this aquifer can be quite variable. Total dissolved solids range from 855 to 3,280 mg/l and averages 1,897 mg/l. Water hardness varies from very hard to soft, but is mostly very hard.

The C sand water has a predominant sodium bicarbonate type but sodium sulfate water can also be detected. Calcium and magnesium are less predominant. Total dissolved solids range from 642 mg/l to 3,733 mg/l and averages 1,773 mg/l. Hardness varies from very hard to soft, but is generally soft.

Water of the Tavis Creek bed shows some tendency to the sodium bicarbonate type. However, predominance of the calcium and magnesium cations, and sulfate and bicarbonate anions is observed in some samples. Total dissolved solids are between 450 mg/l and 5,540 mg/l and averages 1,882 mg/l. The water is soft to hard.

The Coal Lake Coulee bed water shows a tendency to be a sodium bicarbonate-sodium sulfate type, but also has major concentrations of calcium and magnesium. Total dissolved solids range from 1550 mg/l to 5,452 mg/l and averages 2,674 mg/l. The water is generally very hard.

The Hensler sand has a predominant sodium bicarbonate type with major concentrations of sulfate. Calcium and magnesium are less predominant. Total dissolved solids range from 743 mg/l to 2,668 mg/l and averages 1,250 mg/l. The water is generally moderately hard, but can range from very soft to very hard.

7.2.2 SURFACE WATER STUDIES

Background surface water studies and data has been collected since 1981 to present on and adjacent to Falkirk permitted lands. Baseline flow and quality data included ephemeral and intermittent streams and quality and elevation data included permanent wetlands. Water quality testing of the samples was conducted by Minnesota Valley Testing Inc., for total suspended solids, total dissolved solids, pH, total iron, manganese, calcium, sodium, magnesium, electrical conductivity, alkalinity (carbonate and bicarbonate), sulfate, and sodium adsorption ratio Baseline flow quality measurements were performed by Falkirk environmental staff using Stevens recorder gauges and Solinst level-loggers (data logging transducers). Using water level data from the gauges and the transducers, a hydrograph was created to determine the flow rate from a stage-discharge curve. Bentley FlowMaster software is used to perform the hydraulic calculations for the stage-discharge curves.

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Quantification of the surface water probable hydrologic consequences was conducted using the SCS method and the Corps of Engineers’ HEC-1 and HEC-HMS hydrology software. HEC-HMS software was developed in 1995 by the U.S. Army Corps of Engineers Hydrologic Engineering Center and is a Windows-based upgrade to the HEC-1 program. Both software computes the volume of runoff and peak discharges for a given storm event by entering watershed parameters such as the watershed area, weighted curve number, and the time of concentration. These programs will also route flows through a stream channel, culvert, and reservoir, and will combine routed hydrographs to compute peak discharges, time of peak discharges, routed hydrographs, and total runoff volumes. The results of the modeling were used to develop the surface baseline conditions for the permitted areas.

7.3 EARLY GEOTECHNICAL STUDIES

Geotechnical soil drilling has been carried out at the property during several investigations. Studies have been implemented prior to entering a new mining area and periodically throughout the life of the mine when questions arise that warrant further investigation or geotechnical confirmation. The most notable studies concerning geotechnical properties are described below.

In 1976 the intitial Ground Stability Study of the Underwood Coal Field was conducted and reported by Robert L. Zook – Soils / Geological Engieer for the initial mine start up. This was followed in 1981 with a study of the same coal field concentrating on an additional minining unit (Mine Area B) by Barry L. Sutphin – Geotechnical Engineer.

Additional studies for spoil stability and opening the additional mining area in the Riverdale field where completed by J. Lyall Workman, P.E. (Calder & Workman, Inc.) in 1994 and 1995 respectively.

Studies were completed in 1996 and 1998 for moving the 8750 dragline to the Island mining area and the slope stability of that mine area (also by Calder & Workman, Inc.)

In 2009 (Calder & Workman, Inc.), 2010 and 2013 (Barr Engineering) Stability Analyses were completed for highwall stability, site specific clay properties and general spoil stability for both mine areas.

Barr Engineering also completed analysis and impacts of highwall failures and a root cause analysis of the failure around our 8750 dragline in 2015.

To conduct the geotechnical analysis required for the above studies soil data was collected during field investigations and laboratory testing programs. Both conventional continuous overburden coring and cone penetration testing were completed as part of the field investigation.

Laboratory testing included:

•Index properties

◦water content

◦Atterberg Limits

◦grain size distribution

◦dry unit weight

•Shear strength testing

◦uniaxial compression strength

◦direct shear testing

◦undrained triaxial compression testing with pore pressure measurements

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The slope stability analysis was conducted using the SLOPE/w module of GeoStudio software package.

All of these studies have been used to incorporate best practices and supporting data for our ground control plan that is submitted to MSHA. Guidance for such things as our digging method, depth of prebench highwalls, thickness of and angle of dragline highwalls, spoil height and even the best road building materials have all been gleaned from the information provided in the aforementioned geotechnical studies. Figures 7.3 shows the most recent geotechnical borings completed during a mine-wide study in the Underwood mine area. Figure 7.4 shows the most recent geotechnical boring completed during a mine-wide study in the Riverdale mine area.

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Figure 7.3 Underwood Mine Area Geotechnical Borings

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Figure 7.4 Riverdale Mine Area Geotechnical Borings

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8.0 SAMPLE PREPARATION, ANALYSES, AND SECURITY

8.1 SAMPLE COLLECTION AND SHIPMENT

The Falkirk Mine lignite deposits are evaluated on a seam by seam basis. As a standard in the coal industry, individual sections of lignite are bagged and sent to the third-party coal testing laboratory. The procedures at the Falkirk Mine for sample collection are summarized below.

Core runs are specified by the senior and/or field geologist by referencing the geophysical log of the pilot hole. Most of the time a single 10-foot core run can typically capture a full lignite seam. In situations where a coal seam, roof and floor are thicker than 10 feet, a 15-foot core barrel is used or multiple runs with the 10-foot barrel is utilized. Once a specified core run is brought to the surface, the field geologist observes the drillers extract the lignite sample from the double barrel core to ensure the integrity of the sample is maintained, and to verify the top and the bottom of the core run. The core sample is transferred from the core barrel directly to a aluminum trough that contains a fix measureing tape. If there is excess drilling mud from on the core sample the field geologist washes with water, verifies the roof and floor of the lignite core is present and checks the expected coal seam thickness referenced from the pilot hole’s geophysical log to determine coal core recovery. If 90-percent recovery cannot be verified, the driller may attempt to retrieve the remainder of the lignite core run from the current hole. If no successful attempt is made to recover the remaining lignite, the driller must recore the lost interval in a new adjacent core hole.

Upon verifying full recovery of the core run, the field geologist succinctly, but thoroughly logs the lignite run. A typical log describes:

–“To” and “from” depths of burdens and lignite;

–Joints and fractures at specified depths;

–Characteristics of burden above and below the lignite core;

–Roof and floor of lignite seam (i.e. sharp or gradational);

–Presence of pyrite or petrified wood;

–Observations of clay or sands imbedded in the lignite core; and

–Any other prominent characteristics.

Lignite cores may be split into multiple samples for the following reasons:

–Prominent roof, floors, or partings within a continuous seam;

–If visually it appears the quality of the coal good change

Laboratory results for split cores are reviewed by the senior geologist prior to inclusion in the geologic database for modeling. Quality results for all split samples to identify composition concentrations are identified as a continuous seam in the geologic database. The weighted average is computed in the modeling process. Roofs, floors and partings that meet a minable quality are identified as part of the associated seam, and are modeled in the same manner as the split samples described previously. Roofs, floors and partings that do not meet a minable quality are included in the geologic database as a point of record, but are not modeled with a seam identifier, and thus the quality of those splits is not weighted with the associated seam. Total core runs are shipped for analysis following industry standards, thus split samples in the context of a retained sample are not stored at the Falkirk Mine. Lignites tend to be high moisture coals which oxidize rapidly and do not have a long shelf life once removed from the ground. If core splits were retained, they would not be representative of in-situ coal properties over time.

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transferred to the warehouse to be shipped to the third-party laboratory. The Falirk Mine office and warehouse is secured with user specified fob access and camera surveillance. In addition, security officers patrol the property around the clock.

Prior to shipping the samples, the senior geologist reviews each sample against the field records and the chain-of-custody (COC). The date, mine identifier, hole ID, seam ID, and “to” and “from” intervals are verified. In addition to the COC included in the physical shipping container, a copy is emailed to the laboratory manager to notify that a shipment is in route. Copies of the COC forms for coal cores shipped from 2015 through 2021 were available for the QP to review. Coal core samples are shipped to the third-party laboratory via insured freight with tracking information.

8.2 SAMPLE PREPARATION AND ANALYSIS

Minnesota Valley Testing Laboratories, Inc. (MVTL) in Bismarck, North Dakota is the third-party laboratory Falkirk Mine uses for coal core analyses. MVTL has provided coal quality analysis following ASTM standards for over 40 years.

Minimum analyses of coal cores include short proximate (moisture, ash, BTU/lb, sulfur, sodium, calcium), and forms of sulfur. These parameters are the primary quality inputs used to model the Falkirk Mine lignite deposit. Additional analyses of coal cores may include full proximate, ultimate, mineral analysis of ash, trace elements, and ash fusion.

MVTL is in operation Monday through Friday from 8 am to 5 pm. The building is kept secure, and all doors remain locked throughout the day, except the main customer entrance where visitors have to check in and check out. No access is allowed to the laboratory without an escort. During non-operational hours the building is kept locked.

8.3 ASTM Standards

Table 8.1 lists the ASTM standards that MVTL references for various coal quality analyses.


Specific Tests and/or Properties Measured	Specification, Standard, Method, or Test Technique	Items, Materials or Product Tested	Key Equipment or Technology
% Ash	ASTM D7582	Coal	TGA
Calorific Value	ASTM D5865	Coal	Calorimeter
Carbon, Hydrogen, and Nitrogen	ASTM D5373	Coal	Elemental Analyzer
Chlorine	ASTM D6721	Coal	Micro-coulometric Analyzer
Fusibility of Ash	ASTM D1857	Coal	Furnace
Mercury	ASTM D6722	Coal	Direct Combustion Analysis
Mineral Analysis of Ash	ASTM D3682/D5016	Coal	ICP-OES, FIA, Furnace
Oven Dry Moisture	ASTM D7582	Coal	TGA
Air Dry Moisture	ASTM D3302	Coal	Air Dry Ovens
Preparing Samples for Analysis	ASTM D2013	Coal	Crusher / Pulverizer
Sulfur (Total)	ASTM D4239	Coal	Furnace
Sulfur Forms	ASTM D2492	Coal	Gravimetric, AA
Trace Metals	ASTM D6357 Modified	Coal	Microwave Digestion, ICP-MS & ICP-OES
Volatile Matter	ASTM D7582	Coal	TGA

Table 8.1. List of ASTM standards for MVTL.

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8.4 SAFETY

Fire extinguishers, eye wash stations, and safety showers are accessible in the lab. Safety glasses are required throughout the lab. Hearing protection and dust masks are also required in the prep room.

Other protective equipment is available to the staff for use as needed. SDS sheets are maintained in the lab. The building is equipped with a fire alarm system and annual fire and tornado drills are conducted. MVTL maintains a business continuity and disaster plan to cover various incidents of business disruption.

8.5 ROUND ROBIN PROGRAMS

MVTL participates in round-robin testing programs with other laboratories to ensure result accuracy. MVTL participates in an Interlab Coal Round Robin Program monthly. In 2020, MVTL also participated in a lignite (coal) specific round robin program with NACoal including 8 independent laboratories, one of which was MVTL, that were used by various NACoal mine locations. The round robin consisted of four samples labeled 2001, 2002, 2003, and 2004. Two samples were sourced from Red Hills Mine and two samples were sourced from another NACoal mine, Coyote Creek Mine, located in North Dakota. The two locations provided a range of samples with variability in moisture, ash, sulfur and sodium. The labs participating in the round robin were provided 8-mesh splits and dried, 60-mesh splits of all 4 samples. The general results are summarized in Figure 8.1. MVTL is labeled “Laboratory #5”.

Figure 8.1. NACoal 2020 Round Robin Program Summary. (NACoal, 2020)

8.6 BALANCES

All balances are calibrated and certified annually by a third-party calibration service. Balances are verified daily using certified weights.

8.7 SAMPLE RECEIVING AND STORAGE ROOM

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Information Management System (LIMS). Each sample is given a unique lab number used for tracking during analysis and throughout the reporting process.

Samples are stored until they are ready to be crushed in the prep room. There is a slight potential for moisture loss during this storage period. Falkirk acknowledges this potential and, as such, double bags samples in the field to preserve as much in-situ moisture as possible.

8.8 PREP ROOM

A riffled split of 8-mesh coal is placed on a sample tray and weighed. The weights are sent electronically to LIMS for use in the moisture calculation. The tray is placed in an air dry oven and dried overnight. The temperature of the air dry ovens is monitored and recorded daily. The temperature monitoring devices are verified annually. Another riffled split is sealed in a Ziploc bag and retained. The client is notified prior to disposal of the coal core splits.

8.9 LABORATORY TESTING

8.10 QP STATEMENT ON THE ADEQUACY OF SAMPLE PREPERATION, SECURITY AND ANALYTICAL PROCEEDURES

For the past several years, the Falkirk Mine has used a formal outline for the process to collect coal samples at the Falkirk Mine. This has provided consistency in core collection from one drilling program to the next has been thoroughly documented. Between thorough records and personal observation of numerous drilling campaings, it is the QP’s opinion that historic coal core collection has remained consistent with industry standards. The process of double bagging and tagging the cores in addition to multiple checkpoints to log samples from field to shipment to the lab further ensures the integrity and security of each sample is maintained.

Additionally, the QP feels the methodologies used by MVTL are within industry standards for sample preparation, process of sample splitting and reduction, general quality control, and security of samples to ensure that validity and integrity of samples is upheld.

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9.0 DATA VERIFICATION

9.1 DRILLHOLE DATA VERIFICATION

The drilling database for the Falkirk Mine was compiled in an electronic, geologic database. The database encompassed the geologic modeling inputs including lithology picks, total depth of hole, base of oxidation (weathering), hole coordinates, and coal core quality data. This data was organized into three tables related to lithology picks, collar survey, and quality.

The drilling database was saved on the Falkirk network drive which contains the geologic model and has limited access. Files saved on this drive are automatically backed-up daily to a local server.

Once the drilling database was compiled, a series of routine data integrity checks were performed by the QP on the database to check for common errors and omissions. The QP visually inspected the database after updates were made, then ran a second data validation check using Carlson software. The validation checks included, but were not limited to, the following:

- Verified each hole has a unique collar location.

- Verified the total hole depth on the collar table matches the total depth on the lithology table.

- Verified the from and to depths on the lithology table and quality table increase down hole.

- Verified for overlapping intervals in the lithology table based on from and to depths.

- Verified the from and to depths on the quality table match the associated seam depths on the lithology table.

For any errors or omissions reported, the QP reviewed the geophysical logs, field logs, and quality reports related to the specified holes to reconcile the differences.

After the initial checks were performed, the QP person built the initial model. Once modeled, various cross sections and isopach maps were reviewed for anomalies related to structure and/or quality.

It is the QP’s opinion that the analytical results from the coal cores collected during Falkirk’s exploration programs are consistent with actual as-delivered quality from the active mining operations at the Falkirk Mine. This opinion was based on comparison of historical quality projected from the Carlson model for the annual operating plans to actual as-delivered quality indicated by the customer’s (CCSPP) third-party laboratory, MVTL. It is also the QP’s opinion that the modeled structure of the lignite seams is consistent with active mining operations based on comparisons of modeled seam thickness and trends and actual surveyed seam thicknesses and trends.

The QP found the geologic model was a reasonable and reliable representation of the geologic structure and quality of the lignite seams (horizons) at the Falkirk Mine.

Past and ongoing environmental studies including groundwater and surface water studies discussed in Sections 7.2 and 17.3 have been reviewed and it is the QP’s opinion they are thorough, complete, and provide the necessary information for the start up and ongoing operation of the Falkirk Mine. The geotechnical studies discussed in Sections 7.3 and 13.3 have been reviewed and it is the opinion of the QP that the geotechnical data is adequate to support the pit angles used by the Falkirk Mine.

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The Falkirk Mine has established internal policies and controls to manage the environmental, regulatory and social or community aspects for the mining operations. These are periodically reviewed by the QP and other managers at the Falkirk Mine and North American Coal Corporate management for their effectiveness in a culture which follows the principle of continuous improvement.

The Mineral Resource model and other data provided as modifying factors, including those of 3rd party firms, were confirmed as adequate for use in Mineral Reserve Estimation for this TRS.

9.2 LIMITATIONS ON DATA VERIFICATION

Although Falkirk has remained consistent with coal core sampling programs following and documenting procedures that align with coal industry standards, there are still some inherent risks in the estimation of Mineral Resources and Reserves. This risk falls in the uncertainty within the earlier drilling.

Throughout the 50+ year history of the Falkirk Mine’s coalfield, The North American Coal Corporation has always used policies, protocols and procedures to ensure the accuracy and integrity of the drilling and coring data. Experienced geologists have always been on the drill rigs or supervising the engineers and/or students on the drill rigs. However, technologies and understandings change. Prior to 1976, the Falkirk Mine did not have a survey grid established. Hence, drill hole locations and elevations were read from USGS topographic quadrangle maps. Also, prior to 1975, geophysical logging on shallow coal exploration holes was not a common practice. This caused errors and deviations in locations, elevations and depths, especially as compared to more modern methods with higher levels of control. Consequently, all drilling data prior to 1976 has been deleted from Falkirk Mine’s databases and is no longer used for modeling and reserve-resource estimates. Verification of lignite quality and trends with newer drilling data has increased the confidence in the early data, but does not eliminate the inherent risk from lack of QA/QC parameters in this small percentage of data in the areas that have not been mined.

9.3 QP’S STATEMENT OF ADEQUACY OF DATA

Data disclosed in this TRS used for the preparation of geologic models for the purpose of Mineral Resource estimations at the Falkirk Mine have been verified by the QP. The QP has been involved with the verification of these data for the past 17 years and has served as senior mining engineer since 2016. The QP is a registered Professional Engineer in North Dakota; registration number PE-6256. These data include drill hole surveys, geophysical logs, coal core quality, and other relevant test data. Procedures discussed previously in this section follow coal industry standards and were used by the senior geologist and verified by the QP to reconcile any discrepancies upon review of the available data.

It is the QP’s opinion that the data provided for this TRS is more than sufficient for the determination of Mineral Resources and Reserves at the Falkirk Mine.

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10.0 MINERAL PROCESSING

Processing and metallurgical tests were not conducted on the lignite for the Falkirk Mine. It was known early on that the mine and power plant project would only be economic if a run-of-mine product was used as the fuel source. Therefore, no washability or metallurgical tests were conducted.

11.0 MINERAL RESOURCE ESTIMATES

11.1 BASIS FOR MINERAL RESOURCE ESTIMATE

The basis of the Mineral Resource estimates for the Falkirk Mine deposit and the methods in which they were prepared are summarized for this item. The S-K 1300 regulations (17 CFR 229.1300) define a Mineral Resource as:

“A concentration or occurrence of material of economic interest in or on the Earth’s crust in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. A Mineral Resource is a reasonable estimate of mineralization, taking into account relevant factors, such as cut-off grade, likely mining dimensions, location, or continuity, that, with the assumed and justifiable technical and economic conditions, is likely to, in whole or in part, become economically extractable. It is not merely an inventory of all mineralization drilled or sampled.”

The QP based the Mineral Resource estimates presented in Table 11.4 for the Falkirk Mine on a stratigraphic geologic model generated from the verified drilling exploration data presented in Section 7.0 of this TRS. The choice of stratigraphic modeling is due to the continuous spatial continuity of the lignite seams.

11.2 STRATIGRAPHIC MODEL

The QP managed the developement the stratigraphic geologic model for Mineral Resource estimation using Carlson Mining software. All verified drilling data to date was included in the model. The Falkirk Mine lignite deposit was modeled using U.S. customary units projected to NAD 1983 North Dakota State Plane South coordinate system. Key assumptions, parameters and methods to estimate Mineral Resources are discussed herein.

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11.2.1 HORIZONS

The structure of the Falkirk Mine deposit is determined by “to” and “from” depth picks from geophysical logs and field logs correlated the drill hole collar survey. Depth picks represent the roof or floor of a lignite seam which define a horizon or domain.

Table 11.1 presents the stratigraphic Horizons modeled for Mineral Resource estimation. Modeled horizons were required to have quality data in the drilling database to be considered.


HORIZON ID			SEAM NAME
UKNC			Upper Kinneman Creek-Seam
LKNC			Lower Kinneman Creek-Seam
HGA1			Hagel A1-Seam
HGA2			Hagel A2-Seam
HGB1			Hagel B2-Seam
HGB2			Hagel B2-Seam
TRID			Tavis Rider-Seam
UTAV			Upper Tavis-Seam
LTAV			Lower Tavis-Seam
UCLC			Upper Coal Lake Coulee-Seam
LCLC			Lower Coal Lake Coulee-Seam

Table 11.1. Stratigraphic Horizons

In addition to the lignite seam horizons, the pre-mine surface topography, overburden, interburden, parting thickness and the base horizon till (BHTI) depth determined from drill cuttings and geophysical logs.

11.2.2 QUALITY PARAMETERS AND DENSITY DETERMINATION

The quality parameters modeled for determination of Mineral Resources have been modified over the past 38 years by continual evaluations and historical plant performance of the three end users. With the exception of a low BTU value of 5,800 BTU/lb quality parameters aren’t specified in the CSA. Modeled quality parameters include calorific value (Btu/lb), moisture (wt%), ash (wt%), sulfur (wt%), and sodium in ash (wt%); typical Short Proximate analysis reported on an as-received (AR) basis. Five quality grids of the above parameters, along with forms of sulfur are modeled for each horizon. Generally, the only quality constraint on the mineability of the lignite at the Falkirk Mine is weathering/oxidation, which causes a substantial decrease in the heat content of the coal. The lignite existence lines consider the weathering limits of the coal. The low BTU coal is removed from the mineable limits and is not considered as a mineral resource or reserve, therefore there are no quality constraints within the mineable limits of the coal field that can’t be mitigated by blending during mining to meet the customer needs.

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11.2.3 MODELING PROCESS

After the QP verified the drilling data following procedures outlined in Section 9.0 of this TRS, the geologic database including three tables encompassing geologic lithology picks, quality data, and collar surveys was imported into the modeling software.

Once the drilling data was imported, a preliminary topographic surface was created by triangulation of an electronic contour map of the Falkirk Mine and surrounding area. A 200 by 200-foot grid surface was then applied to the triangulated surface. Surveyed drill holes were modeled using inverse distance with a grid cell of 200-feet to create a second topographic grid. Differences in the two modeled topographic surfaces resulted in the designed topographic surface of the mine area.

The lithology and location tables were then referenced by the modeling program and the structural model was developed. The lignite horizons were correlated and modeled using 200-foot grid cells. Missing lithologic data were extrapolated from ten surrounding drill holes using an inverse distance squared calculation. Geologic cross sections were created and correlations checked by the QP. Any errors identified in the lithologic descriptions were reconciled.

Lignite quality was then modeled for the entire deposit. As with the structural model, the quality model uses 200-foot grid cells to model quality of the deposit. Drill holes missing quality data employed an inverse distance squared calculation to assign averaged values from surrounding drill holes.

The lignite existence limits were created by clipping the lignite seams to a model limit. 200-foot grid cells were used to develop this existence model. Next, a limiting quality mask was applied to the modeled horizons. The defined quality limits were applied to the quality grids to remove areas where the lignite quality was not acceptable as a Mineral Resource.

11.2.4 JUSTIFICATION OF MODELING METHODS

Historically, geologic models at the Falkirk Mine have been generated using inverse distance methods. These models were established and used in the development of detailed mine plans, financial projections, landowner tonnage estimates, daily operation plans, and month end reconciliations. The models have proved to be consistent with field conditions (structure and quality), which is attested to the simplified geology of the region as described in Section 6.0 of this TRS. Geologic units are laterally continuous with generally graded quality. Use of inverse distance methods is a coal mining industry standard of geologic modeling. However, to further justify the use of inverse distance modeling methods, the QP along with Carlson software personel, also modeled the drilling data in Carlson software using kriging methods and compared the two model outputs.

Both inverse distance methods and kriging methods resulted in a similar model. The QP did not see a need for Falkirk to alter geologic modeling methods.

11.2.5 QP’s REVIEW AND VALIDATION OF MODEL

The QP serves as the senior mine engineer at the Falkirk, reviewed and validated the geological model using various checks between drill hole data and modeled horizons.

Drill hole locations were randomly selected to verify modeled values of each horizon were representative of the imported drill hole data. Additional visual inspection of the model included review of various consecutive cross sections as well as isopach maps of the modeled structure (roofs, floors, and seam thickness) and quality. Newly modeled grids were also compared to previous models. Changes in modeled values were minor and isolated to areas where new drilling data had been included from recent exploration programs. Anomalies, such as spikes in the data

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were reviewed against the original drill hole data, any errors in the drilling database were reconciled and the model was reconstructed.

The QP feels it is also important to note that the Falkirk Mine is a mining operation actively producing coal. A regular practice in the engineering department is to compare the mined-out pits from the monthly survey data to the geologic model. These comparisons provide a reference for the geologists to verify general trends in the modeled lignite structure.

The QP found the geologic model was a reasonable and reliable representation of the geologic structure and quality of the lignite seams (horizons) at the Falkirk Mine.

11.3 MINERAL RESOURCE ESTIMATES

11.3.1 LIMITS AND CONSTRAINTS ON THE MINERAL RESOURCE ESTIMATES

The Mineral Resources presented in Table 11.4 were estimated by applying a series of geologic and physical limits in addition to high-level mining and economic constraints which meet the level of detail required for an initial assessment (IA). Key constraints used by the QP to determine Mineral Resource estimates are summarized below. Details pertaining to physical constraints are discussed further within sections 3.0 and 17.0 of this TRS. Mining and economic constraints specific to Mineral Resource estimates are discussed herein.

Geologic Constraints:

–Modeled roof and floors of each lignite seam (horizon).

–Base of oxidation assumed to be BHTI or twenty-five feet of overburden unless shown otherwise with drilling

Physical Constraints:

–Topography.

–Lease and fee coal boundaries.

–Offsets from unleased land tracts and occupied dwellings.

–Existing roads and highways, major utilities, and major surface infrastructure without prior agreements for relocation or temporary closure.

–Stream offsets for WOTUS that fall outside of mitigation permits.

Mining and Economic Constraints:

–Resource categorization parameters based on distance from point of observation and drill hole sample count criteria.

–Economics are evaluated annually and compared to market values to determine the economic viability of the mine plan

–Typical quality parameters presented in Table 11.2.


Parameter	Minimum	Maximum
Calorific Value, Btu/lb	5,800	7,000
Moisture, %wt	37.5	37.5
Ash, %wt	5	20
Sulfur, %wt	0.25	2.0
Sodium, %wt	0.5	13

Table 11.2. Typical Quality Parameters (as-received basis).

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11.3.2 GENERATION OF PITS SHELLS FOR MINERAL RESOURCE ESTIMATES

Pits were projected to meet the requirements of the existing contract to provide lignite fuel to the CCSPP as described in the CSA and assumes the continuation of the CCSPP under a new Coal Sales Agreement between Falkirk and Rainbow Energy concurrent with Rainbow Energy’s acquisition of the power plant which is expected to occur in the first half of 2022.

Basic unit costs presented in Table 11.3 were used to determine the maximum reasonable effective stripping ratio of 15:1 for the Falkirk Mine. The sales price has historically remained fairly steady due to the stripping ratio and delivered tons being fairly consistent. Unit costs were derived from general historic unit costs at the Falkirk Mine.


Parameter	Unit	Cost
Burden Removal *	$/BCY	0.62
Royalty	$/ton	0.31

*Burden Removal unit cost was determined assuming the truck-shovel fleet moves approximately 21% of the burden and draglines move 79%. Fleet unit costs are respectively assumed to be $1.25 and $0.45 per cubic yard.

Table 11.3. Unit Costs – Mineral Resource Estimation Parameters.

The geologic model was used to create a map of the deposit. Recovery of in-situ tonnage was assumed to be 100-percent. No dilution factors were applied. Preliminary pits were determined by the QP based on logical mining units, then modified for any physical constraints. General tonnage for areas were calculated in Carlson with a simple closed polyline assuming vertical walls. Lignite quality grids were then individually loaded into Carlson for the QP’s consideration with tonnage estimates to determine a general mine sequence and direction.

Resource pit shells projected through 2032 were used to determine the boundaries for resource estimation.

11.3.3 MINERAL RESOURCE CLASSIFICATION AND CATAGORIZATION

The Mineral Resource categorization applied by the QP includes the consideration of geologic continuity, spatial distribution of drill holes, abundance of data, and quality limits. Mineral Resources presented in this TRS were estimated and categorized under Measured, Indicated, or Inferred categories. The potential of economic extraction is justified by the terms of the existing CSA. Due to the contractual relationship with the customer, it is the QP’s opinion that the prospect of economic extraction is clearly defined.

As discussed in Section 7.2 all drill holes within the Falkirk Mine deposit obtained structural data related to the lignite seams, where a portion of these drill holes also included quality data from the collection of coal core samples. As such, the QP determined it appropriate that limits for spatial distribution between Mineral Resource categories were based on the average cartesian distances between drill holes that contained quality data. Defining the drill hole distances by the drill holes containing quality data ensured an appropriate density of the quality data was included in each Mineral Resource category. Additionally, due to the methodology of the fill-in drilling at the Falkirk Mine, a greater density of quality data would naturally encompass a greater density of structural data.

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Due to the uniformity of the structure and quality of the Falkirk Mine coal field, drill hole distances that will define the spatial distribution between Mineral Resource Categories are based on the drill hole distances currently utilized by Falkirk As stated in Section 7.2, the minimum drill hole spacing within the controlled tracts within the permit boundary area at the Falkirk Mine is 1,320 feet, and fill in drilling tightens the spacing. This drilling density has reliably predicted coal tonnage and quality for over 40 years.

The defined distance limits of the Mineral Resource categories are presented in Table 11.4.


Mineral Resource Category	Lower Distance (Ft)	Upper Distance (Ft)
Measured	0	1,320
Indicated	1,320	2,640
Inferred	2,640	5,280

Table 11.4. Mineral Resource Category Distances.

Measured Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the average distance between quality drill holes is less than or equal to 1,3200 feet. Much of the structural data has an increased density. All of this drilling data was collected by Falkirk using known sampling methods and surveying methods. Due to the level of control and oversight during collection of this drilling data, the resulting resource estimates have a high level of confidence by the QP and a low level of uncertainty.

Indicated Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the average distance between quality drill holes is greater than 1320 feet and less than or equal to 2,640 feet. Due to the level of control and oversight during collection of this drilling data, the resulting resource estimates have a high level of confidence by the QP and a low level of uncertainty.

Inferred Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the average distance between quality drill holes from 2,640 to 5,280 feet. Modeled values at these distances require a large amount of interpolation between drill holes, however due to the level uniformity of the structure and quality data of the Falkirk Mine coal field along with the high level of control and oversight during collection of nearby drilling data, the resulting resource estimates have a moderate level of confidence by the QP and a moderate level of uncertainty.

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11.3.4 MINERAL RESOURCE STATEMENT

The categorized Mineral Resources reported herein are exclusive (or inclusive) of Mineral Reserves. The effective date of Mineral Resource estimates is December 31, 2021.


			Quality
			Calorific Value	Moisture	Ash	Sulfur
Falkirk Mine	Resource Classification	Tonnage	(Btu/lb)	(%wt)	(%wt)	(%wt)
Underwood Field	Measured	31,599,882	6,417	40.41	7.05	0.57
	Indicated	NA	NA	NA	NA	NA
	Measured + Indicated	31,599,882	6,417	40.41	7.05	0.57
	Inferred	NA	NA	NA	NA	NA
Riverdale	Measured	46,820,901	6,614	39.44	6.37	0.58
Field	Indicated	199,721	6,317	37.10	10.69	0.73
	Measured + Indicated	47,020,623	6,612	39.43	6.39	0.58
	Inferred	NA	NA	NA	NA	NA

Total	Measured	78,420,784	6,534	39.83	6.65	0.57
	Indicated	199,721	6.317	37.10	10.69	0.73
Total	Measured+Indicated	78,620,505	6,534	39.82	6.66	0.57

Table 11.5. Mineral Resource Estimates.

11.3.5 UNCERTAINTY OF MINERAL RESOURCE ESTIMATES

Due to the contract provisions of the CSA, factors including contract term or likelihood of economic extraction, lignite sales price, and quality parameters/limits have far less risk of being affected than a mineral sold on the open market. Nonetheless some risks still need to be addressed. Additional exploration may positively or negatively affect Mineral Resource estimates. Furthermore, Mineral Resource estimates may be materially affected by a significant change in the assumptions including general mining costs and land control. New regulations may impose additional economic factors, delays to future permit renewals, or restrictions to physical estimation boundaries. Falkirk assumes the CCSPP will to continue to operate after Rainbow Energy’s acquisition of the power plant, which is expected to occur in the first half of 2022. Numerous regulatory authorities, along with well-funded political and environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation. As a result of such activities, a prematurely retirement of the CCSPP could have a material adverse effect on the mineral resource estimates. The QP is not aware of any specific factors that would currently materially affect the prospect of economic extraction.

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12.0 MINERAL RESERVE ESTIMATES

12.1 BASIS FOR MINERAL RESERVE ESTIMATE

This Item discloses the Mineral Reserve estimates for the Falkirk Mine based on the QP’s detailed evaluation of the modifying factors as applied to indicated or measured mineral resources, which demonstrate economic viability of the Falkirk Mine property. The estimated Mineral Reserves are in accordance with the definitions of “Mineral Reserve” as describe by the S-K 1300 regulations (17 CRF 229.1300) as:

Following definitions presented in 17 CFR 229.1300, and guidance from the Committee for Mineral Reserves International Reporting Standards (CRIRSCO), Mineral Reserves are divided into two categories as listed below and are ranked by increasing level of confidence.

The sample system collects a twice daily (12-hour, midnight to midnight) representative sample of the delivered lignite on the same conveyor belt where the certified conveyor belt scale weighs the tons of lignite delivered over the same period. The conveyor belt is located after the truck dump hopper and storage silos.

This disclosure of Mineral Reserves is based upon the qualified person’s preliminary feasibility study (pre-feasibility or PFS), as defined in 17 CFR Part 229.1300, which includes and supports the qualified person’s determination of Mineral Reserves. A pre-feasibility study was chosen by the qualified person, as opposed to a feasibility study, because the Falkirk Mine has successfully operated for over 40 years and has established a detailed and thorough understanding of the modifying factors that support the conversion of Measured and Indicated Resources to Mineral Reserves for the remaining LOM Plan. The QP does not believe that a feasibility level study is required because of the confidence in the available data.

The mining plans included annual stripping and lignite production qualities and quantities. Annual production costs were estimated based on the mine plan quantities, surface mining methods, equipment fleets in use, and unit prices that have been proven by historical production at the Falkirk Mine. The current mining methods, used at the Falkirk Mine since inception, are planned to continue until enough lignite reserve is depleted to fulfill the contractual obligations of the CSA for fuel supply to the Coal Creek Power Plant.

12.2 MINERAL RESERVE ESTIMATES

12.2.1 KEY ASSUMPTIONS, PARAMETERS, AND METHODS

The following key assumptions, parameters, and methods describe how the QP converted the mineral resources to mineral reserves. All recoverable lignite required to fulfill the contractual obligations of the CSA are contained within the LOM Plan pit extents. The criteria used to estimate the recoverable reserves contained within the LOM pits as estimated by Falkirk include:

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–Mining costs on a unit basis remain relatively consistent with historical performance;

–Minimum minable lignite thickness: approximately 2.0 feet;

–Maximum burden depth: approximately 320 feet;

–Recovery rates by seam presented in Table 13.3 and;

–Maintaining economically competitive costs relative to previous years.

The price and other economic assumptions used to estimate the recoverable reserves are supported by the existing all-requirements CSA, the assumption of a new CSA with Rainbow Energy after Rainbow Energy acquires the CCSPP, and the mine plan associated with these contracts. Compensation from GRE and Rainbow Energy under the CSA’s includes reimbursement of all mine operating costs plus a contractually-agreed fee based on the amount of coal delivered. The CCSPP is located directly next to the Falkirk Mine (i.e. a mine-mouth operation) and 100% of the required coal to operate the CCSPP is sourced from the Falkirk Mine.

The CSA’s eliminate Falkirk’s exposure to spot coal market price fluctuations. As a result of the cost-plus nature of the all-requirements CSA’s and the mine-mouth location of the CCSPP, factors such transportation costs, location and quality of competing coal reserves, and the ability to compete in the market are not relevant considerations in determining the economic feasibility and viability of the coal reserves associated with the Falkirk Mine.

Criteria for determination of Mineral Reserve estimate are justified in further details in the discussion of run-of-mine tonnages under Section 13.0 of this TRS.

Methods to develop the LOM Plan are as follows:

A workplan forecast is developed to determine the schedule and estimated MMBtu requirements of the CCSPP by month for the first eighteen months of the LOM Plan and then by year until the end of the LOM Plan.

To determine initial tonnages for consideration of Mineral Reserves, modifying factors including the minimum mining thickness and dilution parameters are applied to the geologic model used to define Mineral Resources. Quality limits are reassessed on a seam by seam basis. Falkirk engineers then project mining pits in Carlson Software following pit design parameters discussed under Section 13.0 of this TRS. Projections are directed to the topography from the lowest mineable lignite seam. Highwalls are projected at 55-degrees and endwalls are projected at 55-degrees. Volumetric and tonnage data is utilized by the program to determine production and timing schedules.

This process produces a high-level summary by mining unit including rehandle volumes and projected qualities by period.

The high-level summary includes:

–Equipment mechanical and operational availabilities estimated based on historical production;

–Historic production rates of each piece of equipment;

–Fleet capacity including limiting production factors;

–New and/or retiring equipment and;

–Auxiliary equipment allotments.

The total hours, allotted volumes, tonnages and quality by period are the primary inputs for the Falkirk Mine financial model.

After the metered hours for each applicable equipment are calculated to deliver the required tonnages by period, historical equipment costs/hr are applied to determine the total equipment costs for that period. The staff levels are calculated from the required equipment hours and current wages are applied to determine the total labor costs for that period.

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escalated units are then applied to the input hours, volumes, and tonnages previously sequenced to forecast operating costs. In addition to general operating costs, costs pertaining to stockpile inventory adjustments, reclamation, royalties, mine closure, and capital projects are projected and escalated accordingly.

The resulting lignite schedule from the financial model based on the specified delivery schedule determine the Mineral Resources that carry through to become Mineral Reserves.

12.2.2 MINERAL RESERVE STATEMENT

The effective date of Mineral Resource estimates is December 31, 2021.


			Quality
			Calorific Value	Moisture	Ash	Sulfur
Falkirk Mine	Resource Classification	Tonnage	(Btu/lb)	(%wt)	(%wt)	(%wt)
Underwood	Proven	31,599,882	6,417	40.41	7.05	0.57
Field	Probable	NA	NA	NA	NA	NA
	Total	31,599,882	6,417	40.41	7.05	0.57
Riverdale	Proven	46,820,901	6,614	39.44	6.37	0.59
Field	Probable	199,721	6,317	37.10	10.69	0.73
	Total	47,020,623	6,612	39.43	6.39	0.58

Total Reserves	Proven	78,420,784	6,534	39.83	6.65	0.57
	Probable	199,721	6.317	37.10	10.69	0.73
	Total	78,620,505	6,534	39.82	6.66	0.57

Table 12.1. Mineral Reserve Estimates.

12.2.3 QP’S OPINION ON RISK FACTORS THAT COULD MATERIALLY AFFECT MINERAL RESERVE ESTIMATES

The Falkirk Mine has been in operation for over 40 years. Since this is a well-established operation, the deposit, mining, and environmental aspects of the Project are very well understood. The knowledge for the Falkirk is based on the collective experience of personnel from Falkirks’s site operations and technical disciplines gained during years of lignite mining. This knowledge is supported by years of production data and observations at the Falkirk Mine.

The LOM plan included annual stripping and lignite production qualities and quantities. Annual production costs were estimated based on the mine plan quantities, surface mining methods, equipment fleets in use, and unit prices that have been proven by historical production at the Falkirk Mine. The current mining methods, used at the Falkirk Mine since inception, are planned to continue until enough lignite reserve is depleted to fulfill the contractual obligations of the CSA for fuel supply to Rainbow Energy.

Risks include changes in customer demand for any reason, including, but not limited to, dispatch of power generated by other energy sources ahead of coal, fluctuations in demand due to unanticipated weather conditions, regulations or comparable policies which may promote planned and unplanned outages at the customers plant, economic conditions, including an economic slowdown and a corresponding decline in the use of electricity, governmental regulations and/or inflationary adjustments which could have a material adverse effect on Falkirk's mineral reserve estimates.

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At the time of this TRS, the QP is not aware of any specific factors that would currently materially affect the prospect of economic extraction.

The Falkirk Mine Life of Mine Map is shown in Figure 12.1 in the Supplemental Figures Attachment.

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13.0 MINING METHODS

13.1 ANNUAL AND TOTAL LIGNITE PRODUCTION

The Falkirk Mining Company’s Falkirk Mine is a surface lignite mining operation located near Underwood, North Dakota. This operation is a multiple seam mining operation, which is projected to ultimately produce approximately 7.0 million tons per year through 2031. The lignite coal is shipped by conveyor to the CCSPP, located six miles south of Underwood, North Dakota.

13.2 TYPE AND GENERAL MINING METHOD

The primary coal bed is the “Hagel” which is divided into the Upper Hagel (A-1) and Lower Hagel (A-2). These two seams are coincident throughout most of the permit, but are sometimes separated by a clay parting. The Hagel coal bed is overlain in a portion of the permit area by the Kinneman Creek (KNC) seam. This coal seam averages 2.7’ in thickness and ranges from 2.0’-4.3’ within the estimated economically minable area. The KNC seam lies an average of 65’ above the Hagel seam, but varies greatly, from less than 25’ to over 88’ above the Upper Hagel seam. Below the Lower Hagel is a layer of interburden and the final minable “B” seam. The Upper Hagel seam averages 8.5’, and ranges from 3’ - 9’ in thickness. The parting varies from 0’ - 3’ in thickness, and averages less than 1’. Thickness on the Lower Hagel seam ranges from 0’ - 5’ and averages less than 1’ .Throughout most of the present permit area, the parting is absent and the Hagel or A seam averages 8.5’ in thickness. Interburden thickness ranges from 5’ - 25’ and averages 13.5’. The B seam ranges from 1.5’ - 4.5’ and averages 3.5’. Portions have B seam separated into two seams by a parting layer which renders this seam uneconomical to mine due to quality impacts.

These economically minable coal seams are underlain by numerous other seams. The C bed of the Hagel lignite interval is the stratigraphically lowest seam in the Sentinel Butte Formation. The Tavis Creek, Coal Lake Coulee, and Weller Slough beds all occur in the upper portion of the Bullion Creek Formation. These lower coal seams are not economically recoverable by surface mining methods because of prohibitive overburden thickness. However, in portions of the Riverdale 4th Addition, the Tavis Creek and Coal Lake Coulee beds are economically recoverable and are proposed to be mined.

Topsoil and subsoil removal will precede the stripping of the overburden from the areas to be mined. The topsoil lift will be removed until the color change with subsoil is representatively exposed across the stripping area or in accordance with soil survey recommendations. A sufficient volume of subsoil will be removed to respread 24, 36, 42, or 48” of SPGM as required by spoil sampling analyses. An exception is areas of prime soils affected by mine pits, where a total of 48” will be salvaged. In some areas, gravel and sand lenses have been identified in the soil material. These materials will not be salvaged as SPGM, and may be spoiled or used as haulroad fill. Additional material will generally be available in the same area for salvage as indicated on the soil survey map, to guarantee that sufficient SPGM will be available for respread. Characteristically, this topsoil/subsoil removal and respread or stockpiling operation usually occurs during the summer and fall of the year preceding mining. During the fall topsoil/subsoil removal operation, sufficient SPGM will be removed to allow mining operations to continue until April of the following year. The removal and direct respread or stockpiling of the topsoil/subsoil will be accomplished using 32-yard class tractor-scrapers or a truck\shovel fleet.

Stockpiling will be in accordance with the methods approved by the Public Service Commission of North Dakota. Volumes will be measured by load count, ground or aerial survey. The stockpiles will be seeded with an approved mixture to help control wind and water erosion and weed infestation. All stockpiling will be identified by a numbering system labeling each stockpile.

First, the truck and shovel fleet remove overburden to an elevation which approximates the first minable lignite seam; usually this will be the H lignite seam. If, however, the I seam is encountered and determined to have economic value based on quality and thickness it may be recovered as well. This overburden material is hauled to fill in the topography to final grade in the reclamation. Truck and shovel operations may be required to remove other interburdens and rehandle material depending on sequencing/production and reclamation planning.

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Overburden removal operations will be accomplished by the 8750 and 195M draglines as necessary. The draglines will be scheduled to operate a maximum of 21 shifts per week, 52 weeks per year. The 8750 Dragline and 195M Dragline will be used to remove overburden in a single-pass operation (Figure 13.1), with the pit widths varying from 90’ to 300’, depending on the overburden depth and stability of the material in the areas designated to be mined. The draglines will be assisted by a truck-shovel operation for overburden removal. The angle of repose for the spoil piles will vary from 20º to 40º, depending on the geology of the overburden overlying the coal and the depth of burial of the coal. For mine planning purposes, the angle of repose was assumed to be 37º. The highwall slope will also vary due to pit conditions, and will range from 45º to 70º, with the design slope for planning purposes being 60º.

Usually, the dragline is capable of handling 115’ of overburden before it becomes necessary to rehandle. If spoil stability requires overburden to be rehandled, a variety of spoil handling techniques, including chop-cutting, benching, pre-benching with auxiliary equipment, and others, may be used to solve the problems. The remaining overburden material in the pits will be side cast into the adjacent open pit once the coal has been removed. (Figure 13.2) The initial boxcuts will be excavated with 32-yard class tractor-scrapers a truck\shovel fleet, or with a dragline, depending on the location and depth of the overburden, and the availability of the equipment.

Pits dug by the 195M dragline, can vary in direction and length. The boxcut material will be cast into the out of pit spoil area or onto the succeeding pit area if opened by the 195M Dragline. The boxcut material will be hauled into the out of pit spoil area if removed by scrapers or truck and shovel.

Figure 13.1 Typical Range Diagram for Dragline Single Pass

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Figure 13.2 Typical Range Diagram for Dragline Single Pass with Truck-Shovel Prebench

13.3 RUN OF MINE TONNAGES

Recoverable Run of Mine (R-O-M) tonnages at the Falkirk Mine meet the following conditions:

–Minimum mining thickness: 2.0 ft;

–Maximum burden depth: approximately 320 feet;

–Average lignite density: approximately 80 lb/ft3

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The average lignite quality through the LOM is projected to be:


Calorific Value (Btu/lb)			6,200
Moisture (%wt)			37
Ash (%wt)			11.5
Sulfur (%wt)			0.50
Sodium (%wt)			3.13

Table 13.1. Projected LOM Quality.

Recovery rates of individual coal seams are presented in Table 13.2 and were determined from various comparisons between surveyed severed tons, haul truck payloads, delivered tons, and modeled tons accounting for dilution and minimum mining thickness.


Seam			Recovery Rate
Hagel A			91%
Hagel B			85 %
Kinneman Creek			80 %
Tavis			91 %
Coal Lake Coulee			75%

Table 13.2. Recovery Rates by Seam.

The geologic model based on the coal core data are interrogated to establish average yearly coal qualities, based on the actual historical yearly mining areas. These yearly coal qualities (from the model) are then compared to the yearly as-delivered analyses from the power plant.

Mining dilution presented in Table 13.3 was initially determined from like coal at a neighboring location. Later, the drilling data was compared to actual as-delivered quality data and confirmed that the original dilution parameters remained applicable with only slight adjustments. Dilution parameters are applied to all lignite seams and are outlined herein:

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Structural (Roof and Floor)
	Loss thickness (ft)	0.50
	Dilution thickness (ft)	0.56

Quality (Roof and Floor)
	CalorificValue(Btu/lb)(MAF)	12,100
	Moisture (%wt)	22.50
	Ash (%wt)(Dry)	78.8
	Sulfur (%wt)(MAF)	0.05
	Sodium (%wt)(MAF)	1.45

Table 13.3. R-O-M Dilution Parameters.

13.4 ENGINEERING STUDIES – DESIGN PARAMETERS

13.4.1 PIT DESIGN

To determine highwall stability, a circular arc failure approach has been utilized. A minimum FoS of 1.2 was calculated using the Modified Bishop Method for each highwall configuration that will be encountered by the mine. Due to the depth and multiple seam nature of the lignite deposit, benching will be required to allow for continuous burden removal and lignite mining. For individual slopes less than 80 feet, highwall angle are stable up to 70 degrees. Between 80 and 180 feet, the effective slope angle decreases with a linear relationship from 60 to 40 degrees as follows:


Depth (ft)			Effective Highwall Angle
80 to 110			60 degrees
110 to 145			50 degrees
145 to 180			40 degrees

Table 13.4. Effective highwall angle by depth

For slopes greater than 180 feet, benching is required. Figure 13.4 illustrates the combination of highwall slopes and safety benches that are used to meet the effective slopes outlined above. In general, the prebench level, prepared by the truck and shovel operation is located 150 to 160 feet above the pit floor and naturally creates bench with a minimum width of 150 feet. When benches and offsets are accounted for pits may range from 100 to 210 feet in width. Initial design assumes a 170 foot width.

Low wall or spoil side angles were based on the type of materials found throughout the mine area, an angle-of-repose of 33 degrees was recommended by geotechnical studies.

As a whole, pits are designed with an effective highwall angle of approximately 50 degrees, effective endwall angles of approximately 50 degrees, and effective low wall angles of 33 degrees or less.

Mining has been ongoing at the Falkirk Mine since 1978 and the design methodology for the pit slopes has been satisfactory as evidenced by each successful pit progression. Due to the continuous stratigraphic nature of the

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geology, which is checked by regular drilling exploration programs ahead of mining, repetition of geologic units leads to consistency in applying geotechnical parameters.

Falkirk engineering have made minor adjustment to the pit design primarily for optimization, whether that be for new equipment specifications or additional ramps to reduce haul distances. Optimization of drainage is another factor that greatly influences the pit design.

13.4.2 SPOIL STABILITY STUDIES

The bulk of geotechnical studies at the Falkirk Mine since 1976 pertain to spoil stability which influence operation plans for production and reclamation. Many studies have been conducted to verify mining method and direct best practices when entering into a new or unknown mine area. Others have been conducted as a result of either highwall or spoil failures that have been observed at the mine. One such failure occurred at the toe of the dragline bench causing the bench to move vertically downward and horizontally outward toward the spoil piles which lead to a Barr Engineering study in 2015. There have been several failure types observed at the mine, including heaving of the pit floor followed by a slump failure of the highwall or spoil, block failure of the clayey glacial till and wedge failures along fault zones. As a result, there have been several spoil studies performed by qualified engineering firms over the years, including the most recent by Barr Engineering in 2013 titled “Spoil and Highwall Slope Stability Study for Riverdale and Underwood Mine Areas – Falkirk Mine”. The laboratory results were summarized and analyzed using several tests including “One-dimensional swell or settlement potential of soils”, “Moisture-Density Relationship”, “Unconfined Compression test” and “Consolidated Undrained Triaxial Test” all of which are ASTM standard tests. Figure

An example of a slope stability analysis done by Barr is presented in Figure 13.3.

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Figure 13.3. Soil Stability Assessment. (Barr Engineering, 2013)

To help remediate the rotational bench failures, the truck-shovel operation does not dump material within the first two spoil peaks, and spoil piles are not to exceed 90-feet in height above the dragline bench. Furthermore, extra attention is given to ensure water is not stored in spoil valleys for a prolonged period. In addition, the work area is inspected by shift supervisors for cracking, heaving, flowing groundwater, or any other abnormal conditions prior to starting work in an area, and following any precipitation or freeze/thaw event. The inspection requirements are specified as part of Falkirk’s safeguards under the Ground Control Plan. A certified person must document inspections of the work areas during each shift and after every rain, freeze, or thaw. Dragline operators and groundman are continuously monitoring bench and spoil conditions as they dig and utility workers use constant observation of the highwalls and spoils when working in the pits.

A dewatering system, known as the headerline, is installed ahead of mining to facilitate the removal of groundwater and surface water from the mining areas into predetermined pit water ponds. These ponds area monitored by the dewatering supervisors as well as the environmental specialist at the mine.

13.5 HAUL ROADS, RAMPS AND DRAGLINE WALKWAYS

Haul roads and pit ramps are typically designed to a width of 100 feet to allow for two-way traffic. Ditches are constructed in cut sections consisting of 4H:1V inslopes, 15-foot flat ditch bottom, and 3H:1V or flatter backslopes. Haul roads are surfaced with a minimum of 6 inches of aggregate.

Dragline walkways are typically designed to a width of 200 feet. Ditches are constructed in cut sections consisting of 3H:1V inslopes, 14-foot flat ditch bottom, and 3H:1V backslopes.

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Some haul roads may utilize selective fill to improve roadway strength and stability. Two application methods have been employed: application one utilizes 10%-20% selective fill blended uniformly within the road subgrade soil, application two involves subcutting the subgrade and uniformly blending 10%-20% selective fill with the subcut material. Final reclamation of both applications consists of covering any selective fill/soil mixtures with four feet of suitable plant growth material, as well as ensuring any selective fill/soil mixtures are well above the elevation of the expected zone of saturation.

Typical sections for haul roads, pit ramps and dragline walkways are presented in Figure 13.4.

Figure 13.4. Typical sections for roadways.

13.6 PERSONNEL

The Falkirk Mining Company employees approximately 416 full time workforce employees; including maintenance staff and equipment operators; and 70 full time staff employees. In addition to the full time employees, Falkirk employees several seasonal coop and intern employees.

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13.7 MAJOR EQUIPMENT

A list of major and auxiliary equipment used at the Falkirk Mine is presented in Table 13.5 and will be used, as needed, for all aspects of the operations.

List of Major Equipment

2 8750 Draglines (125 cubic yard class)

17 Bulldozers, Track

1 Cable Mover

2 195-M Parting-Reclamation Draglines (17 cubic yard class)

2 Loading Shovels (19 cubic yard class)

1 Loading Shovel (46 cubic yard class)

2 Electric Mining Shovel (63 cubic yard class)

2 Front-End Loaders (16 cubic yard class)

1 Front-End Loader (25 cubic yard class)

1 Front-End Loader (6 cubic yard class)

1 Front-End Loader (5 cubic yard class)

1 Front-End Loader (2 cubic yard class)

1 Explosives Truck

1 Coal Drill

4 100-Ton End-Dump Trucks

9 200-Ton End-Dump Trucks

7 240-Ton End-Dump Trucks

11 Coal Hauler (200-ton)

10 Road Graders

7 Water Trucks

2 Dump Truck

1 Gravel Trailer (35 ton)

3 Excavators

7 Hydraulic Backhoes

1 Supply Truck

3 Mobile Cranes

2 Lowboys

1 Electrical Maintenance Truck

2 Welding Trucks

5 Lube/Fuel Trucks

1 Tire Handling Vehicle

4 Field Maintenance Trucks

36 Portable Pit Pumps

15 Personnel Transport Vehicles

64 Pickup Trucks

8 Scrapers (32 cubic yard class)

Miscellaneous Seeding Equipment

30 Portable Pit Lights

3 Rubber-Tired Doze

1 Overburden Drilling Rig

7 Cable Tractors

6 Farm Tractors

3 Emergency Response Vehicles

Table 13.5. Major and auxiliary equipment list.

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14.0 PROCESSING AND RECOVERY METHODS

No mineral processing is performed.

15.0 INFRASTRUCTURE

The public utility lines and facilities locations are presented in Figure 15.1 (LOM Infrastructure Map, located in the Supplemental Figures Attachment).

The Falkirk Mine receives power from the CCSPP on circuit breaker feeds 61NB1 and 61NB2. Two parallel 69kv transmission lines run two miles from the CCSPP switch yard to the mine office substation. The line then branches out of the mine office substation to feed the East Mine Area and Riverdale Pits. The line that feeds the East Mine Area pit substation has branch feeders along the way that also supply the New Shop substation, Facility substation and the East Heat Enclosure substation. The line that feeds the Riverdale pit substation has a branch feeder that supplies the Riverdale Heat Enclosure substation. The 69kv distribution line network is comprised of thirty-two miles of powerline across the mine site. The East Mine Area and Riverdale Pit substations are scheduled to be advanced ¾ mile in 2022, to accommodate for future mining in those respective areas.

Potable water is supplied to Falkirk from the CCSPP, after treating the water onsite.

Sanitary waste produced at the main Falkirk Mine office and maintenance facility is pumped to a waste pond administered by the CCSPP. Outlying buildings utilize drain fields.

A registered groundwater well sourced from the Hensler Sand aquifer feeds the equipment wash bay and fire hydrants.

Sedimentation ponds W6-02, W6-04, R26-01, and E34-06 serve as the water source for dust suppression water horses located in Sections 6, 26, and 34.

Lignite will be mined and transported to the Falkirk Coal Handling Facility and placed in one of two hoppers for direct delivery to CCS or on the coal stockpile (west of the mine office facilities), via a system of haul roads, by 200-ton payload haul trucks. Public roads are not used for the transport of lignite. Mine site haul routes are depicted in Figure 12.1 (Life of Mine Map). Coal haulage from the East Mine Area will pass through underpasses for US Highways 83 and 200. Coal from the Riverdale Mine Area will utilize underpasses for County Road 20 and 29th Ave NW (Underwood, ND). There is also an at-grade crossing of 2nd Ave SW (Underwood, ND).

16.0 MARKET STUDIES

16.1 MARKETS

The primary market for the Falkirk Mine lignite is the adjacent the CCSPP for which the mine was developed. The Falkirk Mine’s coal quality is such that it is cost prohibitive to transport over long distances. NACoal and Falkirk have made efforts to identify specialty niche markets for the lignite with limited success.

16.1.1 MATERIAL CONTRACTS

The Falkirk Mine is a fully developed and functioning mining operation. All aspects of the mining, haulage and delivery of lignite to the CCSPP are handled by Falkirk. Falkirk is a mine-mouth project where the lignite is delivered directly to the power plant using off highway haul trucks. All production from the mine is delivered to the CCSPP under the existing CSA with GRE and the expected new CSA with Rainbow Energy. Under the CSA, Falkirk receives a contractually-agreed fee based on the amount of lignite delivered. While Falkirk is responsible for

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all mine operations, the customer (GRE currently and Rainbow Energy when the acquisition of the CCSPP by Rainbow is completed) is responsible for funding all mine operating costs and provides all of the capital required to build and operate the mine. This contract structure eliminates exposure to spot coal market price fluctuations. No other material outside contracts are required to provide this service. No material contracts with affiliated parties are in place. Falkirk is an active operation and all material contracts are in place for the continued operation of the mine.

17.0 ENVIRONMENTAL STUDIES, PERMITTING, AND PLANS, NEGOTIATIONS, OR AGREEMENTS WITH LOCAL INDUVIDUALS OR GROUPS

17.1 PERMITS

The Falkirk Mine is operating under the State of North Dakota Public Service Commission (NDPSC) Surface Coal Mining and Reclamation Operations Permits NAFK-8405, Revision 41 and Renewal #7, NAFK-8705, Revision 39 and Renewal #6, NAFK-9503, Revision 33 and Renewal #5 and NAFK-9601, Revision 17. The permits were issued by the State of North Dakota under delegated authority of the United States Department of the Interior, Office of Surface Mining Reclamation Enforcement (OSMRE) Surface Mining Control and Reclamation Act (SMCRA).

A list of active permits at the Falkirk Mine is provided as Table 17.1 below.


	Name and Address of	Identification
Type of Permit	Issuing Authority	Number	Status
State Coal Mining Permit	North Dakota Public Service Commission	NAFK-8405	Issued 04/01/21
	600 East Boulevard, Dept. 408	NAFK-8705	Issued 05/29/19
	Bismarck, North Dakota 58505-0480	NAFK-9503	Issued 04/01/21
		NAFK-9601	Issued 07/07/21

Mine Identification No.	Mine Safety and Health Administration	No. 32-00491	Issued 07/31/75
	U.S. Department of Labor
	P.O. Box 25367, DFC
	Denver, CO 80225

NDPDES Discharge Permit	North Dakota Department of Environmental Quality	No. ND-0024791	Issued 07/02/18
	918 E. Divide Avenue
	Bismarck, ND 58501-1947
Perfected Water Use Permit	North Dakota State Water Commission	#4759	Issued 03/22/1978
	900 East Boulevard Avenue
	Bismarck, ND 58501-1947

Air Pollution Control Permit	North Dakota Department of Environmental Quality	AOP-28093	Issued 04/07/2021
to Operate	Gold Seal Center		Through 04/07/2026
	918 E. Divide Avenue
	Bismarck, ND 58501-1947

Coal Lake Coulee Legal Drain	North Dakota State Water Commission	#1402	Issued 02/25/1981
Permit	900 East Boulevard Avenue
	Bismarck, ND 58505

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Coal Exploration Permit	North Dakota Geological Survey	MCL 55-21-529	Issued 03/01/2021
	600 East Boulevard		Through 03/01/2022
	Bismarck, ND 58505

Conditional Use Permit	Mclean County Board of Commissioners	#40- Case 64	Issued 06/09/1977
	Mclean County Courthouse
	Washburn, ND 58577

Nationwide 404	U.S. Corps of Engineers	Permit #21	Issues 11/16/2017
	Omaha District	Individual Permit	Through 11/16/2047
	Omaha, NE	No. NOW-2017-1364
		-BIS

Stormwater Permit	North Dakota Department of Environmental Quality	#NDR32-0015	Issued 01/01/2020
	Gold Seal Center		Through 12/31/2024
	918 E. Divide Avenue
	Bismarck, ND 58501-1947

Conditional Use Permit	Mclean County Board of Commissioners	Case 65	Issued 06/09/1977
	Mclean County Courthouse	Falkirk Permit No. 40
	Washburn, ND 58577

Conditional Use Permit	Mclean County Board of Commissioners	#591	Issued 03/05/1986
	Mclean County Courthouse	Falkirk Permit
	Washburn, ND 58577	NAFK-8405

Conditional Use Permit	Mclean County Board of Commissioners	#1069	Issued 04/16/1993
	Mclean County Courthouse	Falkirk Permit
	Washburn, ND 58577	NAFK-8405

Conditional Use Permit	Mclean County Board of Commissioners	#848	Issued 04/13/1989
	Mclean County Courthouse	Falkirk Permit
	Washburn, ND 58577	NAFK-8705

Conditional Use Permit	Mclean County Board of Commissioners	#1237	Issued 03/19/1996
	Mclean County Courthouse	Falkirk Permit
	Washburn, ND 58577	NAFK-8705

Conditional Use Permit	Mclean County Board of Commissioners	#1235	Issued 04/17/1996
	Mclean County Courthouse	Falkirk Permit
	Washburn, ND 58577	NAFK-9503

Conditional Use Permit	Mclean County Board of Commissioners	#1367	Issued 04/22/1997

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	Mclean County Courthouse	Falkirk Permit
	Washburn, ND 58577	NAFK-9503

Conditional Use Permit	Mclean County Board of Commissioners	#1521	Issued 03/14/2000
	Mclean County Courthouse	Falkirk Permit
	Washburn, ND 58577	NAFK-9503

Conditional Use Permit	Mclean County Board of Commissioners	#1255	Issued 07/02/1996
	Mclean County Courthouse	Falkirk Permit
	Washburn, ND 58577	NAFK-9601

Conditional Use Permit	Mclean County Board of Commissioners	#1686	Issued 05/07/2002
	Mclean County Courthouse	Falkirk Permit
	Washburn, ND 58577	NAFK-8705

Conditional Use Permit	Mclean County Board of Commissioners	#1687	Issued 05/07/2002
	Mclean County Courthouse	Falkirk Permit
	Washburn, ND 58577	NAFK-9503

User of High Explosives	Federal Explosives Licensing Center	License #3-ND-055	Issues 07/01/2021
	Bureau of Alcohol, Tobacco, Firearms and Explosives	-33-6G-00045	Through 07/01/2024
	244 Needy Road
	Martinsburg, WV 25401-9431

Conditional Use Permit	Mclean County Board of Commissioners	#1951	Issued 06/06/2024
	Mclean County Courthouse	Falkirk Permit
	Washburn, ND 58577	NAFK-9503

Conditional Use Permit	Mclean County Board of Commissioners	#2144	Issued 06/19/2006
	Mclean County Courthouse	Falkirk Permit
	Washburn, ND 58577	NAFK-8405

Conditional Use Permit	Mclean County Board of Commissioners	#2210	Issued 04/23/2007
	Mclean County Courthouse	Falkirk Permit
	Washburn, ND 58577	NAFK-8405

Conditional Use Permit	Mclean County Board of Commissioners	#2622	Issued 12/22/2010
	Mclean County Courthouse	Falkirk Permit
	Washburn, ND 58577	NAFK-9503

Conditional Use Permit	Mclean County Board of Commissioners	#3547	Issued 11/21/2017
	Mclean County Courthouse	Falkirk Permit
	Washburn, ND 58577	NAFK-8405

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Temporary Water Use Permit	North Dakota State Water Commission	PermitND2020-20184	Issued 06/01/2020
	900 East Boulevard Avenue	Falkirk Permit	Through 05/31/2021
	Bismarck, ND 58505	NAFK-8405

Solid Waste Permit	North Dakota Department of Environmental Quality	Falkirk Permit No.	Issued 01/01/2020
	Gold Seal Center	WH-2463	Through 01/01/2030
	918 E. Divide Avenue
	Bismarck, ND 58501-1947

Table 17.1. List of Active Permits

17.2 ENVIRONMENTAL STUDIES

Baseline studies have been conducted on all Falkirk permitted lands and have been approved through the NDPSC. An Environmental Assessment (EA) was issued on two quarters of Federal Coal in December, 2016. The impacts of the Falkirk Mine were considered during the NDPSC permitting process and the EA process. No impacts were anticipated with mining at the Falkirk Mine. Some of the areas that were evaluated were:

–Air Resources

–Geology

–Soils

–Groundwater Resources

–Surface Water Resources

–Streams and Wetlands

–Alluvial Valley Floors

–Threatened and Endangered Species

–Land Use

–Cultural and Historical Resources

–Transportation Facilities

–Existing Structures

–Hazardous and Solid Waste

17.3 BASELINE STUDIES

17.3.1 GROUNDWATER

There are about 575 groundwater monitoring wells in the Falkirk Mine database. U.S. Office of Surface Mining personnel and others have commented that this is possibly the largest number of monitoring wells at any western US surface coal mine.

The main source of water for the surrounding farmsteads is from private ground water wells. Consequently, Falkirk has been monitoring the ground water in the Underwood Coal Field since 1976 and in the Riverdale Coal Field since 1994. Many farmsteads also receive water from a rural water system. Currently the city of Underwood receives its municipal water from the City of Riverdale. Well certification programs have also been established for the monitoring of production wells in the area.

The analysis of quality, and potentiometric fluctuation patterns has been conducted for the last 30 years of data (1989-2019) for the Underwood Coal Field, and for 26 years in the Riverdale Coal Field based on water level measurements started in 1994.

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The Falkirk Mining Company ground water monitoring plans developed for and implemented at the Falkirk Mine is intended to fulfill the requirements of North Dakota Administrative Code sections 69-05.2-09-12 and 69-05.2-16-14. The purpose behind the design and implementation of the ground water monitoring plan is threefold; investigate and quantify the pre-mining hydrologic conditions of permitted and adjacent areas, monitor impacts on the ground water hydrology of the area due to surface mining operations and climatic conditions, and monitor and quantify post-mining ground water conditions. A sustained program of ground water data collection also serves to substantiate projected impacts to the hydrology of the permit area as outlined in the probable hydrologic consequences section of each permit application.

The current monitoring well inventory for the Falkirk Mine is listed in Section 2. (NAFK-8405, NAFK-8705, NAFK-9503 and NAFK-9601). This inventory includes active, inactive, and destroyed monitoring wells. Active and inactive wells are listed first, and destroyed wells are placed toward the end of the inventory. Section 2.2 (NAFK-8405, NAFK-8705, NAFK-9503 and NAFK-9601) also lists the frequency at which water levels and water quality samples are taken. In addition to the monitoring schedule, the Well Inventory and Monitoring Schedule lists the location of the well, top of casing and ground surface elevations, depths to the top and bottom of the well screen, and the stratum in which the monitoring well is located. All available monitoring well installation and construction information is also contained in Section 2.2. (NAFK-8405, NAFK-8705, NAFK-9503 and NAFK-9601). Information is included for active, inactive, and destroyed wells. As required by NDAC 69-05.2-08-06(1)(d), available lithologic logs, geophysical logs, well construction reports and diagrams, and well completion reports are presented.

Water quality samples will be analyzed, at a minimum, for the parameters required by NDAC 69-05.2-08-06(1)(e). Sample results will be reported to the North Dakota Public Service Commission annually within 30 days following the fourth calendar quarter. Wells with adequate water production will be sampled after purging, at a minimum, the volume of stale water calculated to exist in the well, or when the water’s measured parameters for pH and electrical conductivity have reached stabilization. Low producing wells will be purged, allowed to recover, and sampled within twenty-four hours of purging. Wells with insufficient water volume to allow for collection of a representative sample will be documented to that effect in the annual groundwater quality report, in addition to any other condition that may prevent a well from being sampled.

A minimum of two years of baseline ground water data was collected and studied within, and extending a mile beyond, each permit area at the Falkirk Mine. The baseline data collection included water levels, water qualities (alkalinity, hardness, total dissolved solids (TDS), major cation/anions, and select metals), potentiometric head, flow direction, and hydraulic conductivity calculated from pumping tests or single well response (slug) tests. Also, as part of the permitting process, domestic wells and springs within and surrounding the permit areas are certified to determine the well or spring location, well construction details, source aquifer, water chemistry, and pumping or flow rate.

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17.3.2 SURFACE WATER

From 1981 through present baseline surface water quality and quantity data has been collected from thirty-five ephemeral and intermittent stream monitoring sites and quality and elevation data on five permanent wetlands. Additional quality samples were taken on approximately twenty-seven developed water resources (dugouts and stock ponds), forty-eight springs and seeps and one hundred forty seasonal and semi-permanent wetlands. Samples were collected by Falkirk environmental staff and contracted environmental professionals in accordance with Section 69-05.2-08-07, NDAC.

The study area encompassed the Falkirk Mine four permitted areas (NAFK-8405, NAFK-8705, NAFK-9503 and NAFK-9601). Water quality parameters tested by a third-party laboratory included but not limited to total suspended solids, total dissolved solids, pH, total iron, manganese, calcium, sodium, magnesium, electrical conductivity, alkalinity (carbonate and bicarbonate), sulfate, and sodium adsorption ratio. Water quality analysis results for Total Dissolved Solids values ranged from 24 to 3800 mg/l, Total Suspended Solid values ranged from <1 to 3760 mg/l, Specific Conductance values ranged from 43 to 4270 umhos/cm and pH values ranging between 6.3 and 9.8. Based on baseline flow data, the average unit runoff for the permit area watersheds ranges from 0.05 to 300 cfs.

17.3.3 GEOCHEMISTRY

A geochemical investigation of the overburden and underburden soils down through and immediately below the lowest seam projected to be mined within the planned mining disturbance boundary of the permitted areas has been completed. Overburden samples were collected from drillholes in each permit area at a minimum density of one drillhole per 40 acres across the projected mining disturbance boundary; equaling at least 16 overburden drillholes per section of land. Overburden samples are collected at 5 foot increments down to the top of target lignite, and then the 5 feet immediately below. Each sample is collected from the drill cuttings, bagged separately, and sent for laboratory analysis. Over the entire Falkirk Mine area, approximately 1,076 individual drillholes sites have had overburden samples collected and analyzed from them. The majority of the overburden samples were analyzed by MVTL or Agvise Laboratories.

17.3.4 ARCHEOLOGY

Evaluation of cultural resources at the Falkirk Mine have been completed with the North Dakota Historical Society per requirements of NDCC 55-03 as authorized to conduct cultural resources investigations in the State of North Dakota.

Archaeological surveys have been conducted on all of the Falkirk Mine approved State Mining Permits (NAFK-8405, NAFK-8705, NAFK-9503, and NAFK-9601). Included was the Class III Cultural Resource Inventory, evaluation testing on the sites that were identified during inventory and final mitigation work approved by the North Dakota State Historic Preservation Officer (NDSHPO).

In Permit NAFK-8405, thirty-six historic sites and fifty-two prehistoric sites were identified. The NDSHPO determined twelve sites were listed as eligible for the National Register and eleven of the sites were mitigated. In Permit NAFK-8705, eighteen historic sites and fifteen prehistoric sites were identified. The NDSHPO determined one site was listed as eligible for the National Register and that one site was mitigated. In Permit NAFK-9503, eighty-eight historic sites and forty-eight prehistoric sites were identified. The NDSHPO determined twenty sites was listed as eligible for the National Register and that one site nineteen were mitigated. In Permit NAFK-9601, eleven historic sites and eight prehistoric sites were identified. The NDSHPO determined two sites were listed as eligible for the National Register and one of the sites was mitigated.

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17.3.5 WATERS OF THE US (WOTUS)

The Falkirk Mine received an Individual Permit (NOW-2017-1364-BIS) from the Department of the Army Corps of Engineers, Omaha District in November, 2017. This permit covers all of Falkirk’s permitted lands and is authorized until November, 2047.

17.4 WASTE DISPOSAL

No processing of lignite occurs at the Falkirk Mine; therefore, no lignite processing wastes will be generated.

Disposal of waste in the permit area will be restricted to non-coal waste for which an Inert Solid Waste Permit is not required. The non-coal waste including concrete products, plastic material, wood materials, and other non-hazardous materials will be placed and stored in a controlled manner in a designated approved portion of the permit area, in accordance with Section 69-05.2-19-04, NDAC. Disposal of the above referenced non-coal waste will occur in approved mining pits on lands under Falkirk ownership.

17.5 SITE MONITORING

The Falkirk Mine has sampling plans for areas that are required to be monitored on a regular basis including water (ground and surface water) sampling and soil sampling.

17.5.1 WATER SAMPLING

As part of a long-term water monitoring program, groundwater monitoring wells and surface water sampling locations were selected on pre-mining and post-mining lands. Currently, 356 monitoring wells targeting various water bearing units are sampled for quality,13 ephemeral streams and intermittent streams are sampled for surface water quality and flow data and five permanent wetlands are sampled for water quality and elevation data is collected Groundwater and surface water samples are collected, analyzed, and reported to NDPSC and the North Dakota Department of Environmental Quality (NDDEQ) Upon collection, water samples are shipped in coolers to Minnesota Valley Testing Laboratories, Inc. in Bismarck, ND for analysis.

Quality parameters tested during these sampling events include but are not limited to total suspended solids, total dissolved solids, pH, total iron, manganese, calcium, sodium, magnesium, electrical conductivity, alkalinity (carbonate and bicarbonate), sulfate, and sodium adsorption ratio. These data are compared to the baseline groundwater and surface water conditions established from 1981 to present on and adjacent to Falkirk permitted lands.

Upon mine closure, an appropriate post mine groundwater and surface water sampling program that follows regulatory requirements will be outlined with NDPSC and the NDDEQ and followed.

17.5.2 SOIL SAMPLING

Section 69-05.2-15, NDAC, allows for determining SPGM replacement thickness based on regraded spoil characteristics. After the spoil material has been regraded, samples will be collected to a depth of 12 inches on a 400-foot grid. They will be analyzed for SAR and texture. Analytical results supporting the proposed soil respread depth will be submitted with the grade approval request to the North Dakota Public Service Commission.

In accordance with Section 69-05.2-15-05, NDAC, nutrients and soil amendments (in the amounts determined by soil tests) will be applied to the redistributed surface soil layer when necessary so that it supports the approved post-mining land use and meets revegetation requirements. All soil tests will be performed by a qualified laboratory using standard methods. Soil samplings are analyzed by Agvise Laboratories in Northwood, ND.

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17.6 WATER MANAGEMENT

Surface runoff from lands disturbed by surface coal mining facilities and activities at the Falkirk Mine are controlled by sedimentation ponds. Discharges from these impoundments are regulated under an individual NDPDES permit, Permit Number ND-0024791, issued by the NDDEQ. The NDPSC performance standards for dams and embankments are also followed in accordance with section 69-05.2-20, NDAC.

In addition, a Storm Water Pollution and Prevention Plan (SWPPP) dated August 2021 is in place and discusses in detail the water management practices at the Falkirk Mine. Stormwater Best Management Practices (BMPs) for the reduction of erosion and sedimentation are also discussed in the SWPPP. This plan is in place for surface coal mining haulroads that are located outside of a watershed that are controlled by sedimentation pond. The SWPP permit is regulated under NDPDES general permit for stormwater discharges from mining, General Permit Number NDR320000.

Currently, 70 active sedimentation ponds are in use at the Falkirk Mine in all permitted areas for the collection and treatment of surface water runoff within the mine area. Also, the Falkirk Mine has twenty-seven stormwater outfall control sites

Sedimentation ponds at the Falkirk Mine are either discharged by a control valve or are pumped. To comply with the mine site’s NDPDES permit for discharges, water samples are collected and analyzed once per month for a pond discharge for total suspended solids and pH and annually for Iron. Daily visual inspections are made during discharges for quality, flow rate and oil and grease. Water samples are shipped in coolers to Minnesota Valley Testing Laboratories, Inc. in Bismarck, ND for analysis. These quality results are reported quarterly via the electronic Discharge Monitoring Reports (DMRs) through NDDEQ.

17.7 RECLAMATION BOND

Falkirk Mine is required to post a reclamation bond in accordance with Section 69-05.2-12-07 of the North Dakota Administrative Code. The reclamation costs for Permits NAFK-8405, NAFK-8705 and NAFK-9503 have been calculated by utilizing the methods and procedures as outlined by the Public Service Commission’s “Guideline for estimating reclamation costs for establishing performance bond amounts for permit areas.” The current reclamation bond that is in place for Falkirk’s active permits is $99,450,000.

17.8 PLANS, NEGOTIATIONS, OR AGREEMENTS WITH LOCAL INDIVIDUALS OR GROUPS

Temporary closures of county roads within the permitted area were reviewed and approved by the Board of County Commissioner of McLean County, North Dakota. Road Closures, relocations and operations within 100' of R-O-W currently approved are listed in Falkirk’s approved State Mining Permits.

17.9 MINE CLOSURE PLANS

The current LOM plan assumes closure of the mine in 2031. At that time reclamation and remediation work would begin, including the closure of pits and other mine facilities, respreads of topsoil/subsoil, and revegetation. Monitoring and other costs are included for a ten-year period after the completion of reclamation. The SMCRA permit details post production reclamation activities and long-term management plans for mined lands and all disturbed areas. Financial assurance for the ultimate reclamation of facilities is documented in the reclamation plan, and security for costs that will be incurred to execute site closure is provided by a third-party insurer to the State of North Dakota in the form of a surety bond. The amount of the financial security as of December 31, 2021 is $99,450,000.

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17.10 QP’s OPINION OF ADEQUECY OF CURRENT PLANS

There are no outstanding permits related to the LOM plan awaiting regulatory approval. The Falkirk Mining Company currently has all permits in place to operate and adhere to the current mine plan. Excluding any regulatory changes out of the Falkirk’s Mine control, the QP does not anticipate hurdles for approval of future renewal applications. The QP bases this opinion on the mine’s history to meet regulatory requirements. No NOVs have been issued at the Falkirk Mine in the past three years. Proper monitoring plans following QA/QC procedures have been in place at the Falkirk Mine since the mine’s inception and are documented through regular reporting to the NDPSC and the NDDEQ. Furthermore, appropriate bonding and closure plans are in place.

17.11 DESCRIPTION OF ANY COMMITMENTS TO ENSURE LOCAL PROCUREMENT AND HIRING

Positions at the Falkirk Mine are posted with North Dakota Job Service and are posted on the North American Coal Website for all job seekers. Falkirk also participates at local college job fairs for student internships.

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022

18.0 CAPITAL AND OPERATING COSTS

18.1 OPERATING COSTS

Annual production costs were estimated in conjunction with the mining methods discussed in Section 13 to satisfy the contractual terms of the CSA. All costs were estimated on the assumption that all lignite would be delivered to the existing truck dump. Costs are escalated at various rates depending on the predicted performance of the Consumer/Producer Price Index with 2021 being the base year.

All costs were estimated to a PFS level of study based on historical costs and performance measures that have been maintained by Falkirk since its inception. These costs are reviewed and verified on an annual basis to account for changes in site conditions or the operating plan. This information was then used to estimate the projected costs for the Life of Mine (LOM). Table 18.1 provides a summary of the assumptions that were used to develop these projected costs.


	Annual Average
Dragline Overburden*	83,765,000	CY
Truck/Shovel Overburden*	22,297,000	CY
Virgin Stripping Ratio	13.06
Delivered Tons	8,119,000	Tons
Lignite cost per MMBTU	$2.03	/MMBTU

Quality:
Heating Value	6,297	BTU/LB
Moisture	37.50%
Sulfur	0.50%
Ash	10.76%

*Includes re-handle

Table 18.1. LOM Cost Assumptions.

All costs including the costs required for mine development, burden removal, severing of the coal, reclamation, delivery of the coal to the power plant along with the necessary maintenance required to keep all equipment operating safely and efficiently are paid by CCSP, as per the CSA. Falkirk is then paid a profit based on delivered tons. All mine closing costs are also required to be paid by CCSPP under the CSA. As mine closing dollars are expended, Falkirk is reimbursed by CCSPP

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022


	2022	2023	2024	2025	2026
Direct Costs	$123,069,123	$123,322,482	$128,188,119	$131,312,456	$134,138,655
Indirect Costs	$41,204,970	$37,971,634	$37,977,486	$37,988,626	$38,804,706
Total Cost	$164,274,093	$161,294,116	$166,165,606	$169,301,082	$172,943,361

	2027	2028	2029	2030	2031
Direct Costs	$140,540,077	$143,851,003	$151,713,715	$156,019,253	$158,205,299
Indirect Costs	$43,401,232	$45,089,792	$49,307,331	$50,768,983	$51,806,186
Total Cost	$183,941,309	$188,940,795	$201,021,046	$206,788,236	$210,011,484

Table 18.2. LOM Operating Costs.

18.2 CAPITAL COSTS

Captial Costs were estimated to a PFS level of study based on past equipment purchase history and vendor quotes. Captial Costs include equipment expenditures, mine development, mitigation, and land acquisitions. All capital costs incurred by the Falkirk Mine are provided by or reimbursed by the customer as required under the terms of the CSA’s. There are risks regarding the capital costs estimates, including escalating costs of raw materials, equipment availability and timing due to either production delays or supply chain gaps. Future capital costs included in the LOM plan are expected to total approximately $59.0 MM. The estimated annual capital costs are summarized in Table 18.3. Should the CSA be extended beyond 2031, additional capital costs would be required and funded by CCSPP.

Table 18.3. Capital Costs.

19.0 ECONOMIC ANALYSIS

19.1 KEY ASSUMPTIONS, PARAMETERS AND METHODS

The primary assumption for the development of the economic plan is the continued operation of the CCSPP, the existing CSA with GRE and the CSA with Rainbow Energy following the acquisition of the CCSPP by Rainbow Energy that is expected to occur in the first half of 2022 and the resultant required annual deliveries. The analysis of economic viability is supported by the all-requirements CSA’s and the LOM plan that supports the CSA’s. The CSA’s requires the customer to fund all mine operating costs, including final mine reclamation, and provide all of the capital required to build and operate the mine. This contract structure eliminates exposure to spot coal market price fluctuations. As a result of the cost-plus nature of the all-requirements CSA and the mine-mouth location of CCSPP, factors such transportation costs, location and quality of competing coal reserves, and the ability to compete in the market are not relevant considerations in determining the economic feasibility and viability of the coal reserves associated with the Falkirk Mine.

Although the LOM plan assumes mining ceases in 2031, the term may be shortened or extended at the option of the customer. Any tons remaining after mining ceases in 2031 within the LOM plan are considered a resource.

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022

A reduction in dispatch or the premature closure of CCSPP would have a material adverse effect on the economic viability of the Falkirk Mine reserves.

Section 18 outlines the methodology for the generation of the operating cost estimate.

–The LOM production plan is based primarily on dragline operations that project timing for the truck/shovel fleets as well as coal loading operation and reclamation equipment. All using the surface mining methods outlined in the Ground Control Plan. Other key assumptions are as follows:

–Coal production is estimated to run through 2031 and post-mining reclamation through 2046;

–Total number of employees are approximately 416 (could vary with coal demand);

–Diesel price has been estimated at $2.40/gallon and escalated at 2% per year in this projection;

–Wages and benefits were escalated at an annual rate of 3%

19.2 ANNUAL CASH FLOWS

The Net Present Value, Internal Rate of Return and capital payback period is not applicable due to the ongoing nature of this project and cost-plus feature of the CSA. The cost-plus nature of the CSA provides assurance that all costs incurred by Falkirk will be reimbursed by the customer and negates any risk of loss to Falkirk and allows the mine to remain cash flow positive in 2022 and remain so through the end of the CSA. Post-mining reclamation work represents a legal requirement to return the land to its original state following the termination of coal deliveries. During the reclamation period, the customer will reimburse Falkirk for all direct costs incurred related to the reclamation of the minesite.

19.3 SENSITIVITY ANALYSIS

Over the history of the mine, Falkirk has performed numerous LOM studies based on various tonnage requirements requested by the customer. Increased tonnage decreases the overall production cost per ton as fixed costs can be spread over additional tons. For every 100,000 ton annual reduction, costs are estimated to increase approximately $0.10/ton. The inverse has also been shown such that for every 100,000 ton annual increase, the overall cost of production is estimated to be reduced by approximately $0.10/ton. As a result, CCSPP has historically operated at the highest possible production rates.

The Falkirk Mine’s profit correlates proportionally with the actual increase or decrease in tonnage required by the customer as compensation under the CSA includes reimbursement of all mine operating costs plus a contractually-agreed fee based on the amount of coal delivered. It was assumed all costs in the LOM are economical based on the customer approval of the LOM plan, which was escalated utilizing the key assumptions outlined previously. One of the largest cost components within the plan that fluctuates is diesel fuel. A cost of $2.40 per gallon for diesel price was assumed. If the cost of diesel goes up 50%, the final average selling price of coal will go from $2.03 per million BTU to $ $2.13 per million BTU, respectively.

20.0 ADJACENT PROPERTIES

There are no properties adjacent to the Falkirk Mine. There is no information used in this TRS that has been sourced from adjacent properties. No public drilling information was available or sourced for the development of the geological model.

The drilling and exploration activities at the Falkirk Mine defines the lignite geology, Mineral Resources and Mineral Reserves. Due to this and the relatively simple geology at the Falkirk Mine, material changes to the Mineral Resource estimates and Mineral Reserve estimates are not likely if adjacent property information is included in future estimates.

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022

21.0 OTHER RELEVANT DATA AND INFORMATION

In the QPs opinion, all material information has been stated in the above sections of this TRS.

22.0 INTERPRETATIONS AND CONCLUSIONS

Interpretations and conclusions of the Mineral Resource QP and Mineral Reserve QP are provided herein. This is the first TRS filed with the SEC following S-K Subpart 1300 regulations. Mineral Resource and Reserve estimations prior to December 31, 2021 were reported following guidance of Industry Guide 7.

22.1 GEOLOGY AND MINERAL RESOURCE ESTIMATES

23.0 RECOMMENDATIONS

Continue current practices and reconciliations of actual to budget lignite recoveries, qualities, and costs. Update LOM plan projections and economic analyses accordingly.

The QP has no recommendations for additional work outside the scope of the existing LOM plan.

SEC S-K 1300 Technical Report Summary

The Falkirk Mining Company 02/14/2022

24.0 ADDITIONAL REFERENCES

Bluemle, John P., 1971, Geology of McLean County, North Dakota, North Dakota Geological Survey Bulletin 60, Part 1, 65 pp.

Brophy, John A., undated, A Synopsis of the Geology and Groundwater Resources of Mercer, Oliver, and McLean Counties, North Dakota, With a discussion of Effects of Lignite Strip Mining on Groundwater Systems, Lewis and Clark 1805 Regional Council for Development, 38pp

CRIRSCO. (2019, November). The International Reporting Template.

Groenewold, Gerald H., LeRoy A. Hemish, John A. Cherry, Bernd W. Rehm, Gary N. Meyer and Laramie M. Winczewski, 1979, Geology and Geohydrology of the Knife River Basin and Adjacent Areas of West-Central North Dakota, North Dakota Geological Survey Report of Investigation Number 64, 402 pp.

Groenewold, G. H., R. D. Koob, B. W. Rehm, W. M. Peterson, and G. A. McCarthy, 1982, Geological and Geochemical Controls on the Chemical Evolution of Subsurface Water in Undisturbed and Surface-Mined Landscape in Western North Dakota, 180 pp.

Klausing, Robert L., 1971, Ground Water Basic Data, McLean County, North Dakota, North Dakota Geological Survey Bulletin 60, Part II, 468 pp.

Klausing, Robert L. 1974, Ground Water Resources of McLean County, North Dakota, North Dakota Geological Survey Bulletin 60, Part III, 73 pp

Moran, Stephen R. and John A. Cherry, 1977, Subsurface Water Chemistry in Mined-Land Reclamation: Key to Development of a Productive Post-Mining Landscape, Proceedings of Second Annual General Meeting, Canadian Land Reclamation Association, August, 1977, Edmonton, Alberta, Paper No. 4, 29 pp

Moran, Stephen R. and John A. Cherry, 1978, Analysis of the Hydrologic Response of Aquifers at Surface-Mine Sites in Western North Dakota, presented at the 31st Canadian Geotechnical Conference, October, 1978, Winnipeg, Manitoba, 42 pp.

Moran, Stephen R., Gerald H. Groenewold and John A. Cherry, 1978, Geologic, Hydrologic, and Geochemical Concepts and Techniques in Overburden Characterization for Mined Land Reclamation, North Dakota Geological Survey Report of Investigation No. 63, 152 pp.

NACoal. (2020, November 30). 2020 Lignite Coal Quality Round Robin.

Rehm, Bernd W., 1979, Hagel Bed Aquifer Test, Underwood, North Dakota, unpublished preliminary report, Engineering Experiment Station. University of North Dakota, 61 pp.

Rehm, Bernd W., Gerald H. Groenewold, and William A. Peterson, 1980, Mechanisms, Distribution, and Frequency of Groundwater Recharge in an Upland Area of Western North Dakota, North Dakota Geological Survey Report of Investigation No. 75, 72 pp.

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022

PROPERTY LOCATION

The Falkirk Mine is located approximately 4 miles south of Underwood, North Dakota (ND) or approximately 7.5 miles northwest of Washburn, ND, in McLean County, which is approximately 55 miles north of Bismarck, ND. The entrance to the mine is by means of a paved road, 1st Street SW, that is located approximately 2 mile west of Highway 83. The general location of the Falkirk Mine is shown on Figure 1.0. Coal Creek Station is located just south of the mine.

Figure 1.0. Location of the Falkirk Mine.

LOCAL RESOURCES AND INFRASTRUCTURE

The towns of Underwood and Washburn are located within ten miles of the mine, with other small communities also nearby. Numerous employees also reside in Bismarck and Mandan, a distance of about 50 miles.

The Falkirk Mine receives both its power and water from Coal Creek Station. However, Falkirk’s East shift change building receives water from McLean-Sheridan Rural Water. Fuel for equipment is supplied by multiple local vendors including: Farstad Oil, Missouri Valley Petroleum, and Enerbase Cooperative Resources.

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022

The main entrance to the Falkirk Mine is accessed by traveling north from Bismarck on State Highway 83 for approximately 50 miles, then going west on the access road, 1st Street SW located four miles south of Underwood. The mine office is located two miles to the west.

Travel to the Falkirk Mine by air is possible using the Bismarck Airport in Bismarck, ND, approximately 55 miles south of the mine, and then using ground transportation, traveling via US Highway 83

The main railway systems near the Falkirk Mine are Canadian Pacific, BNSF, and Dakota Missouri Valley & Western (DMVW). DMVW crosses through the Falkirk Mine Reserve.

LEASES

Falkirk holds 335 leases granting the right to mine approximately 43,486 acres of coal interests and the right to utilize about 24,323 acres of surface interests. In addition, Falkirk owns in fee about 40,666 acres of surface interests and 1,800 acres of coal interests. The leases and deeds are recorded at the McLean County courthouse and are a matter of public record. Substantially all of the leases were acquired in the 1970’s and have been replaced with new leases and/or have continuation provisions that generally permit the leases to be continued beyond their fixed terms. The leases obligate Falkirk to make payments based on the amount of lignite mined from the subject property. Most royalty rates range from $.08 - $.16 per ton of lignite mined. A few leases include annual escalator provisions. Payments may also include surface damage payments and advanced or minimum royalty payments. Production royalties are calculated monthly based on surveys and are generally paid on a quarterly basis, although in certain situations royalties are paid monthly.

Table 1.1 shows The Falkirk Mining Company leases and Table 1.2 shows the Falkirk Mining Company acquisitions.

Table 1.1 The Falkirk Mining Company - Leases


Lease Id	Lease Type	Lease Date	Lease Expiration Date
3RO-03637	Coal Lease Agreement	9/18/1997	9/17/2017

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022


3RO-03638	Coal Lease Agreement	10/20/1997	10/19/2017
3RO-03639	Coal Lease Agreement	1/29/1998	1/28/2018
3RO-03641	Surface & Coal Lease Agreement	1/6/1999	1/5/2009
3RO-03645	Surface & Coal Lease Agreement	2/11/2003	2/10/2013
3RO-03646	Coal Lease	10/30/2003	10/29/2033
3RO-03647	Coal Lease	10/30/2003	10/29/2033
3RO-03648	Coal Lease	10/30/2003	10/29/2033
3RO-03649	Coal Lease	10/30/2003	10/29/2033
3RO-03650	Coal Lease	10/30/2003	10/29/2033
3RO-03652	Coal Lease	10/30/2003	10/29/2033
3RO-03653	Coal Lease	10/30/2003	10/29/2033
3RO-03654	Coal Lease	10/30/2003	10/29/2033
3RO-03655	Surface & Coal Lease Agreement	6/9/2004	6/8/2044
3RO-03656	Coal Lease Agreement	2/22/2007	2/21/2047
3RO-03657	Coal Lease Agreement	3/9/2007	3/8/2047
3RO-03658	Surface & Coal Lease Agreement	6/11/2007	6/10/2027
3RO-03659	Surface & Coal Lease Agreement	6/11/2007	6/10/2027
3RO-03660	Surface & Coal Lease Agreement	7/10/2007	7/9/2047
3RO-03661	Coal Lease Agreement	10/4/2007	10/3/2047
3RO-03662	Surface & Coal Lease Agreement	12/13/2007	12/12/2047
3RO-03663	Coal Lease Agreement	9/29/2007	9/28/2047
3RO-03664	Surface & Coal Lease Agreement	3/7/2008	3/6/2048
3RO-03665	Coal Lease Agreement	3/8/2008	3/7/2048
3RO-03666	Coal Lease Agreement	3/7/2008	3/6/2048
3RO-03667	Surface & Coal Lease Agreement	3/20/2008	3/19/2048
3RO-03668	Coal Lease Agreement	6/4/2008	6/3/2048
3RO-03669	Coal Lease Agreement	3/28/2008	3/27/2048
3RO-03670	Surface & Coal Lease Agreement	4/2/2008	4/1/2048
3RO-03671	Coal Lease Agreement	5/31/2008	5/30/2048
3RO-03672	Coal Lease Agreement	6/4/2008	6/3/2048
3RO-03673	Coal Lease Agreement	6/19/2008	6/18/2028
3RO-03674	Surface & Coal Lease Agreement	7/3/2008	7/2/2048
3RO-03675	Coal Lease Agreement	7/3/2008	7/2/2028
3RO-03676	Surface & Coal Lease Agreement	7/18/2008	7/17/2048
3RO-03677	Coal Lease Agreement	7/16/2008	7/15/2048
3RO-03678	Coal Lease Agreement	8/26/2008	8/25/2048
3RO-03679	Surface & Coal Lease Agreement	12/13/2008	12/12/2048
3RO-03680	Surface & Coal Lease Agreement	5/5/2009	5/4/2049
3RO-03681	Coal Lease Agreement	12/17/2009	12/16/2049
3RO-03682	Coal Lease	7/29/2010	7/28/2055
3RO-03683	Coal Lease	7/29/2010	7/28/2055
3RO-03684	Coal Lease	7/29/2010	7/28/2055
3RO-03685	Coal Lease	7/29/2010	7/28/2055
3RO-03686	Coal Lease	7/29/2010	7/28/2055
3RO-03687	Coal Lease	7/29/2010	7/28/2055
3RO-03688	Coal Lease Agreement	5/12/2010	5/11/2050
3RO-03689	Coal Lease Agreement	5/12/2010	5/11/2050

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022


3RO-03690	Surface & Coal Lease Agreement	5/12/2010	5/11/2050
3RO-03691	Surface & Coal Lease Agreement	5/12/2010	5/11/2050
3RO-03692	Surface & Coal Lease Agreement	3/25/2010	3/24/2050
3RO-03693	Coal Lease	7/14/2014	7/13/2019
3RO-03694	Coal Lease Agreement	9/11/2017	9/10/2037
3RO-03695	Coal Lease Agreement	8/21/2017	8/20/2037
3RO-03696	Coal Lease Agreement	9/15/2017	9/14/2037
3RO-03697	Coal Lease Agreement	10/4/2017	10/3/2037
3RO-03698	Coal Lease Agreement	10/7/2017	10/6/2037
3RO-03699	Coal Lease Agreement	10/11/2017	10/10/2037
3RO-03700	Coal Lease Agreement	10/13/2017	10/12/2037
3RO-03701	Coal Lease Agreement	10/10/2017	10/9/2037
3RO-03702	Coal Lease Agreement	9/25/2017	9/24/2037
3RO-03703	Coal Lease Agreement	10/20/2017	10/19/2037
3RO-03704	Coal Lease Agreement	10/23/2017	10/22/2037
3RO-03705	Coal Lease Agreement	12/7/2017	12/6/2037
3RO-03706	Coal Lease Agreement	12/14/2017	12/13/2037
3RO-03707	Coal Lease Agreement	1/26/2018	1/25/2038
3RO-03708	Coal Lease Agreement	3/7/2018	3/6/2038
3RO-03709	Coal Lease Agreement	3/9/2018	3/8/2038
3RO-03710	Coal Lease Agreement	3/15/2018	3/14/2038
3RO-03711	Surface & Coal Lease Agreement	4/16/2018	4/15/2043
3RO-03712	Surface & Coal Lease Agreement	4/17/2018	4/16/2043
3RO-03713	Surface & Coal Lease Agreement	4/19/2018	4/18/2043
3RO-03714	Surface & Coal Lease Agreement	4/20/2018	4/19/2043
3RO-03715	Surface & Coal Lease Agreement	4/23/2018	4/22/2043
3RO-03716	Surface & Coal Lease Agreement	5/25/2018	5/24/2043
3RO-03717	Surface & Coal Lease Agreement	5/29/2018	5/28/2043
3RO-03718	Surface & Coal Lease Agreement	8/8/2018	8/7/2043
3RO-03719	Surface & Coal Lease Agreement	11/1/2018	10/31/2043
3RO-03720	Surface & Coal Lease Agreement	11/6/2018	11/5/2043
3RO-03721	Surface Lease Agreement	1/28/2020	1/27/2040
3RV-03255	Exploration Contract & Coal Lease	9/12/1972	9/11/2013
3RV-03261	Exploration Contract & Coal Lease	8/28/1972	8/27/2013
3RV-03280	Exploration Contract & Coal Lease	8/30/1972	8/29/2013
3RV-03281	Exploration Contract & Coal Lease	8/30/1972	8/29/2013
3RV-03283	Exploration Contract & Coal Lease	9/12/1972	9/11/2013
3RV-03284	Exploration Contract & Coal Lease	9/13/1972	9/12/2013
3RV-03285	Exploration Contract & Coal Lease	9/12/1972	9/11/2013
3RV-03310	Coal Lease	8/15/1962	8/14/2002
3RV-03311	Coal Lease	5/24/1962	5/23/2002
3RV-03316	Coal Lease	6/8/1962	6/7/2002
3RV-03317	Coal Lease	2/12/1964	2/11/2004
3RV-03321	Coal Lease	1/25/1962	1/24/2002
3RV-03322	Coal Lease	2/16/1962	2/15/2002
3RV-03323	Coal Lease	1/12/1967	1/11/2017
3RV-03324	Coal Lease	11/21/1969	11/20/1994
3RV-03325	Coal Lease	1/23/1962	1/22/2002

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022


3RV-03326	Coal Lease	9/11/1962	9/10/2002
3RV-03327	Coal Lease	9/25/1962	9/24/2002
3RV-03329	Coal Lease	5/23/1962	5/22/2002
3RV-03330	Coal Lease	2/16/1962	2/15/2002
3RV-03331	Coal Lease	5/29/1962	5/28/2002
3RV-03332	Coal Lease	1/16/1967	1/15/2007
3RV-03337	Coal Lease	1/26/1962	1/25/2002
3RV-03339	Coal Lease	5/29/1962	5/28/2002
3RV-03340	Coal Lease	2/21/1962	2/20/2002
3RV-03341	Coal Lease	5/25/1962	5/24/2002
3RV-03342	Coal Lease	5/22/1962	5/21/2002
3RV-03345	Coal Lease	2/9/1962	2/8/2002
3RV-03347	Coal Lease	12/8/1969	12/7/1994
3RV-03348	Coal Lease	12/16/1970	12/15/2015
3RV-03355	Coal Lease	11/9/1971	11/8/2016
3RV-03356	Coal Lease	11/9/1971	11/8/1996
3RV-03360	Coal Lease	11/11/1971	11/10/2016
3RV-03362	Coal Lease	11/29/1971	11/28/1996
3RV-03363	Coal Lease	1/24/1972	1/23/1997
3RV-03367	Coal Lease	8/22/1972	8/21/1997
3RV-03378	Coal Lease	11/29/1972	11/28/1997
3RV-03382	Coal Lease	3/6/1973	3/5/1998
3RV-03386	Coal Lease	5/11/1973	5/10/1998
3RV-03387	Coal Lease	8/7/1973	8/6/1998
3RV-03392	Coal Lease	4/25/1974	4/24/2014
3RV-03393	Coal Lease	5/7/1974	5/6/2014
3RV-03399	Exploration Contract & Coal Lease	7/27/1971	7/26/2012
3RV-03407	Coal Lease	6/11/1974	6/10/2014
3RV-03408	Coal Lease	5/28/1974	5/27/2014
3RV-03409	Coal Lease	6/11/1974	6/4/2014
3RV-03410	Coal Lease	6/12/1974	6/4/2014
3RV-03411	Coal Lease	6/5/1974	6/4/2014
3RV-03412	Coal Lease	6/14/1974	6/4/2014
3RV-03416	Coal Lease	6/14/1974	6/4/2014
3RV-03417	Coal Lease	6/12/1974	6/11/2014
3RV-03418	Coal Lease	8/30/1974	8/29/2014
3RV-03420	Coal Lease	9/19/1974	9/18/2014
3RV-03421	Coal Lease	10/12/1974	10/11/2014
3RV-03422	Coal Lease	10/11/1974	10/10/2014
3RV-03423	Coal Lease	11/22/1974	11/21/2014
3RV-03424	Coal Lease	12/5/1974	12/4/2014
3RV-03425	Coal Lease	12/9/1974	12/8/2014
3RV-03426	Coal Lease	12/10/1974	12/9/2014
3RV-03427	Coal Lease	12/11/1974	12/10/2014
3RV-03428	Coal Lease	12/31/1974	12/30/2014
3RV-03429	Coal Lease	12/30/1974	12/29/2014
3RV-03430	Coal Lease	12/15/1974	12/14/2014
3RV-03431	Coal Lease	1/2/1975	1/1/2015

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022


3RV-03433	Coal Lease	3/11/1975	3/10/2015
3RV-03436	Exploration Contract & Coal Lease	8/19/1972	8/18/2013
3RV-03437	Exploration Contract & Coal Lease	8/18/1972	8/17/2013
3RV-03439	Exploration Contract & Coal Lease	8/30/1972	8/29/2013
3RV-03442	Exploration Contract & Coal Lease	9/5/1972	9/4/2013
3RV-03444	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3RV-03447	Exploration Contract & Coal Lease	8/21/1972	8/20/2013
3RV-03450	Exploration Contract & Coal Lease	8/31/1973	8/30/1994
3RV-03451	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3RV-03452	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3RV-03454	Exploration Contract & Coal Lease	9/12/1972	9/11/2013
3RV-03455	Exploration Contract & Coal Lease	9/12/1972	9/11/2013
3RV-03456	Exploration Contract & Coal Lease	9/11/1972	9/10/2013
3RV-03457	Exploration Contract & Coal Lease	8/31/1972	8/30/2013
3RV-03458	Exploration Contract & Coal Lease	9/12/1972	9/11/2013
3RV-03459	Exploration Contract & Coal Lease	9/12/1972	9/11/2013
3RV-03460	Exploration Contract & Coal Lease	8/21/1972	8/20/2013
3RV-03461	Exploration Contract & Coal Lease	9/11/1972	9/10/2013
3RV-03465	Exploration Contract & Coal Lease	5/26/1972	5/25/2013
3RV-03472	Coal Lease	8/19/1971	8/18/1996
3RV-03482	Coal Lease	6/25/1974	6/24/2014
3RV-03483	Coal Lease	6/25/1974	6/24/2014
3RV-03484	Coal Lease	6/25/1974	6/24/2014
3RV-03485	Coal Lease	6/25/1974	6/24/2014
3RV-03486	Coal Lease	6/25/1974	6/24/2014
3RV-03501	Exploration Contract & Coal Lease	5/26/1972	5/25/2013
3RV-03504	Exploration Contract & Coal Lease	5/25/1972	5/24/2013
3RV-03523	Exploration Contract & Coal Lease	5/22/1972	5/21/2013
3RV-03526	Exploration Contract & Coal Lease	5/27/1972	5/26/2013
3RV-03528	Exploration Contract & Coal Lease	5/24/1972	5/23/2013
3RV-03529	Exploration Contract & Coal Lease	5/25/1972	5/24/2013
3RV-03532	Exploration Contract & Coal Lease	5/23/1972	5/22/2013
3RV-03539	Exploration Contract & Coal Lease	6/5/1972	6/4/2013
3RV-03542	Exploration Contract & Coal Lease	5/24/1972	5/23/2013
3RV-03543	Exploration Contract & Coal Lease	5/25/1972	5/24/2013
3RV-03547	Exploration Contract & Coal Lease	5/24/1972	5/23/2013
3RV-03550	Exploration Contract & Coal Lease	5/30/1972	5/29/2013
3RV-03554	Exploration Contract & Coal Lease	5/23/1972	5/22/2013
3RV-03568	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3RV-03569	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3RV-03600	Exploration Contract & Coal Lease	7/23/1971	7/22/2012
3RV-03601	Exploration Contract & Coal Lease	7/21/1971	7/20/2012
3RV-03609	Exploration Contract & Coal Lease	7/21/1971	7/20/2012
3RV-03611	Exploration Contract & Coal Lease	8/6/1971	8/5/2012
3RV-03624	Coal Lease	1/19/1982	1/18/2022
3RV-03625	Coal Lease	1/19/1982	1/18/2022
3UN-03006	Exploration Contract & Coal Lease	9/23/1971	9/22/2012
3UN-03007	Exploration Contract & Coal Lease	9/23/1971	9/22/2012

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022


3UN-03008	Exploration Contract & Coal Lease	3/3/1973	3/2/2014
3UN-03009	Exploration Contract & Coal Lease	7/23/1971	7/22/2012
3UN-03010	Exploration Contract & Coal Lease	7/22/1971	7/21/2012
3UN-03011	Exploration Contract & Coal Lease	11/22/1972	11/21/2013
3UN-03017	Exploration Contract & Coal Lease	7/22/1971	7/21/2012
3UN-03019	Exploration Contract & Coal Lease	3/3/1973	3/2/2014
3UN-03023	Exploration Contract & Coal Lease	7/22/1971	7/21/2012
3UN-03026	Lease	10/1/1971	9/30/2011
3UN-03027	Exploration Contract & Coal Lease	9/22/1971	9/21/2012
3UN-03032	Exploration Contract & Coal Lease	5/18/1973	5/17/2014
3UN-03035	Exploration Contract & Coal Lease	8/5/1971	8/4/2012
3UN-03040	Exploration Contract & Coal Lease	10/5/1971	10/4/2012
3UN-03041	Exploration Contract & Coal Lease	8/10/1978	8/9/2011
3UN-03043	Exploration Contract & Coal Lease	10/7/1971	10/6/2012
3UN-03045	Exploration Contract & Coal Lease	10/9/1971	10/8/2012
3UN-03050	Coal Lease	8/24/1977	8/15/2027
3UN-03051	Coal Lease	8/24/1977	8/23/2027
3UN-03053	Exploration Contract & Coal Lease	7/29/1971	7/28/2012
3UN-03054	Lease	8/22/1973	8/21/1998
3UN-03057	Exploration Contract & Coal Lease	9/23/1971	9/22/2012
3UN-03058	Exploration Contract & Coal Lease	7/24/1971	7/23/2012
3UN-03059	Exploration Contract & Coal Lease	7/26/1971	7/25/1992
3UN-03060	Exploration Contract & Coal Lease	10/5/1971	10/4/2012
3UN-03061	Exploration Contract & Coal Lease	7/27/1971	7/26/1992
3UN-03066	Exploration Contract & Coal Lease	7/28/1971	7/27/2012
3UN-03067	Exploration Contract & Coal Lease	10/1/1971	9/30/2012
3UN-03071	Exploration Contract & Coal Lease	7/27/1971	7/26/2012
3UN-03077	Exploration Contract & Coal Lease	7/27/1971	7/26/2012
3UN-03079	Exploration Contract & Coal Lease	7/24/1971	7/23/2012
3UN-03082	Exploration Contract & Coal Lease	7/20/1971	7/19/2012
3UN-03083	Exploration Contract & Coal Lease	7/21/1971	7/20/2012
3UN-03084	Exploration Contract & Coal Lease	7/20/1971	7/19/2012
3UN-03085	Exploration Contract & Coal Lease	1/30/1973	1/29/2014
3UN-03088	Exploration Contract & Coal Lease	7/27/1971	7/26/2012
3UN-03096	Exploration Contract & Coal Lease	7/29/1971	7/28/2012
3UN-03102	Exploration Contract & Coal Lease	9/28/1971	9/27/1992
3UN-03114	Exploration Contract & Coal Lease	9/30/1971	9/29/2012
3UN-03115	Exploration Contract & Coal Lease	7/29/1971	7/28/2012
3UN-03117	Exploration Contract & Coal Lease	9/28/1971	9/27/2012
3UN-03123	Exploration Contract & Coal Lease	7/22/1971	7/21/2012
3UN-03126	Exploration Contract & Coal Lease	7/22/1971	7/21/2012
3UN-03128	Exploration Contract & Coal Lease	7/31/1971	7/30/2012
3UN-03129	Exploration Contract & Coal Lease	8/6/1971	8/5/2012
3UN-03130	Exploration Contract & Coal Lease	9/27/1971	9/26/2012
3UN-03132	Exploration Contract & Coal Lease	7/20/1971	7/19/2012
3UN-03135	Exploration Contract & Coal Lease	10/4/1971	10/3/2012
3UN-03137	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3UN-03139	Exploration Contract & Coal Lease	4/12/1972	4/11/2013

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022


3UN-03140	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3UN-03141	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3UN-03142	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3UN-03143	Exploration Contract & Coal Lease	4/12/1972	4/11/2013
3UN-03154	Exploration Contract & Coal Lease	8/16/1973	8/15/1994
3UN-03155	Exploration Contract & Coal Lease	10/10/1973	1/9/1994
3UN-03191	Coal Lease	5/14/1974	5/13/2014
3UN-03196	Coal Lease	8/19/1971	8/18/1996
3UN-03197	Coal Lease	6/25/1974	6/24/2014
3UN-03198	Coal Lease	6/25/1974	6/24/2014
3UN-03199	Coal Lease	6/25/1974	6/24/2014
3UN-03200	Coal Lease	6/25/1974	6/24/2014
3UN-03201	Coal Lease	6/25/1974	6/24/2014
3UN-03204	Lease	3/27/1980	3/26/1990
3UN-03205	Lease	3/27/1980	3/26/1990
3UN-03206	Lease	3/27/1980	3/26/1990
3UN-03207	Lease	3/27/1980	3/26/1990
3UN-03208	Coal Lease	1/19/1982	1/18/2022
3UN-03209	Coal Lease	1/19/1982	1/18/2022
3UN-03220	Coal Lease	11/15/1972	11/14/1997
3UN-03221	Coal Lease	11/15/1972	11/14/1997
3UN-03230	Coal Lease	4/4/1973	4/3/1998
3UN-03231	Coal Lease	8/21/1973	8/20/1998
3UN-03232	Coal Lease	8/21/1973	8/20/1998
3UN-03233	Coal Lease	8/21/1973	8/20/1998
3UN-03241	Coal Lease	7/28/1997	6/30/2017
3UN-03242	Surface Lease Agreement	11/27/1995	11/26/2035
3UN-03252	Coal Lease	5/1/2003	4/30/2023
3UN-03253	Surface & Coal Lease Agreement	11/11/2005	11/10/2015
3UN-03800	Coal Lease	4/26/2007	4/25/2037
3UN-03801	Coal Lease	4/26/2007	4/25/2037
3UN-03803	Coal Lease	4/26/2007	4/25/2037
3UN-03804	Lease	9/1/1975	12/31/2045
3UN-03805	Coal Lease	1/1/2018	12/31/2037
3UN-03806	Exploration Contract & Coal Lease	4/2/1973	4/1/2014
3UN-03807	Surface & Coal Lease Agreement	5/16/2016	5/15/2036
3UN-03808	Surface & Coal Lease Agreement	11/1/2016	10/31/2036
3UN-03809	Surface & Coal Lease Agreement	11/1/2016	10/31/2036
3UN-03810	Surface & Coal Lease Agreement	11/2/2016	11/1/2036
3UN-03811	Surface & Coal Lease Agreement	11/3/2016	11/2/2036
3UN-03812	Surface & Coal Lease Agreement	10/31/2016	10/30/2036
3UN-03813	Surface & Coal Lease Agreement	1/4/2017	1/3/2037
3UN-03814	Surface & Coal Lease Agreement	12/29/2016	12/28/2036
3UN-03815	Surface & Coal Lease Agreement	3/2/2017	3/1/2037
3UN-03816	Surface & Coal Lease Agreement	4/19/2017	4/18/2027
3UN-03817	Coal Lease Agreement	6/1/2017	1/29/2013
3UN-03818	Coal Lease Agreement	7/14/2017	7/13/2037

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022


3UN-03819	Coal Lease Agreement	7/18/2017	7/17/2037
3UN-03820	Surface & Coal Lease Agreement	6/19/2018	6/18/2038
3UN-03821	Coal Lease Agreement	6/18/2018	6/17/2038
3UN-03822	Coal Lease Agreement	6/18/2018	6/17/2038
3UN-03823	Coal Lease Agreement	7/3/2018	7/2/2038
3UN-03824	Coal Lease Agreement	9/18/2018	9/17/2038
3UN-03825	Surface Lease Agreement	9/18/2018	9/17/2038
3UN-03826	Surface & Coal Lease Agreement	2/5/2019	2/4/2039
3UN-03827	Surface & Coal Lease Agreement	2/12/2019	2/11/2039
3UN-03828	Surface & Coal Lease Agreement	3/21/2019	3/20/2039
3UN-03829	Coal Lease	11/20/2018	11/19/2048
3UN-03830	Coal Lease	11/20/2018	11/19/2048
3UN-03831	Coal Lease	11/20/2018	11/19/2048
3UN-03832	Coal Lease	11/20/2018	11/19/2048
3UN-03833	Coal Lease Agreement	1/9/2020	1/8/2050
3UN-03835	Surface & Coal Lease Agreement	7/20/2020	7/19/2040
3UN-03836	Surface & Coal Lease Agreement	4/22/2020	4/21/2040
3UN-03837	Surface & Coal Lease Agreement	4/14/2020	4/13/2040
3UN-03838	Surface Lease Agreement	12/31/2019	12/30/2039
3UN-03839	Coal Lease	6/12/2020	6/11/2050
3UN-03840	Coal Lease Agreement	8/26/2020	8/25/2040
3UN-03841	Coal Lease Agreement	8/26/2020	8/25/2040
3UN-03842	Coal Lease Agreement	8/27/2020	8/26/2040
3UN-03843	Surface Lease Agreement	12/16/2020	12/15/2040
3UN-03844	Coal Lease Agreement	9/9/2020	9/8/2040
3UN-03845	Coal Lease Agreement	11/28/2020	11/27/2040
3UN-03846	Coal Lease Agreement	11/30/2020	11/29/2040
3UN-03847	Coal Lease Agreement	12/2/2020	12/1/2040
3UN-03848	Coal Lease Agreement	12/2/2020	12/1/2040
3UN-03849	Coal Lease Agreement	12/3/2020	12/2/2040
3UN-03850	Coal Lease Agreement	12/3/2020	12/2/2040
3UN-03851	Coal Lease Agreement	12/5/2020	12/4/2040
3UN-03852	Coal Lease Agreement	12/7/2020	12/6/2040
3UN-03853	Coal Lease Agreement	12/12/2020	12/11/2040
3UN-03854	Coal Lease Agreement	12/16/2020	12/15/2040
3UN-03855	Coal Lease Agreement	1/5/2021	1/4/2041
3UN-03856	Coal Lease Agreement	8/19/2021	8/18/2041
3UN-03857	Coal Lease Agreement	8/24/2021	8/23/2041

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022

Table 1.2 The Falkirk Mining Company - Acquisitions


Agreement Id	Agreement Type	Agreement Date	Agreement Expiration Date
3-FKC001	Warranty Deed	8/19/1985	12/31/2099
3-FKC002	Warranty Deed	6/11/1987	12/31/2099
3-FKC003	Warranty Deed	9/16/1988	12/31/2099
3-FKC004	Warranty Deed	12/13/1991	12/31/2099
3-FKC005	Mineral Deed	2/19/1993	12/31/2099
3-FKC006	Mineral Deed	10/25/1993	12/31/2099
3-FKC007	Mineral Deed	1/3/1994	12/31/2099
3-FKC008	Warranty Deed	7/12/1994	12/31/2099
3-FKC009	Warranty Deed	7/15/1996	12/31/2099
3-FKC010	Mineral Deed	1/8/1998	12/31/2099
3-FKC011	Mineral Deed	1/26/1999	12/31/2099
3-FKC012	Warranty Deed	2/24/1999	12/31/2099
3-FKC013	Warranty Deed	11/8/2000	12/31/2099
3-FKC014	Mineral Deed	2/22/2006	2/21/2105
3-FKS001	Warranty Deed	10/6/1975	12/31/2099
3-FKS002	Warranty Deed	8/12/1975	12/31/2099
3-FKS003	Warranty Deed	8/29/1975	12/31/2099
3-FKS004	Warranty Deed	8/29/1975	12/31/2099
3-FKS005	Warranty Deed	10/6/1975	12/31/2099
3-FKS006	Warranty Deed	10/6/1975	12/31/2099
3-FKS007	Warranty Deed	10/6/1975	12/31/2099
3-FKS008	Warranty Deed	10/6/1975	12/31/2099
3-FKS009	Warranty Deed	10/6/1975	12/31/2099
3-FKS010	Warranty Deed	8/4/1976	12/31/2099
3-FKS011	Warranty Deed	4/18/1985	12/31/2099
3-FKS012	Warranty Deed	5/5/1980	12/31/2099
3-FKS013	Warranty Deed	6/20/1980	12/31/2099
3-FKS014	Warranty Deed	7/29/1980	12/31/2099
3-FKS015	Warranty Deed	10/31/1980	12/31/2099
3-FKS016	Warranty Deed	10/31/1980	12/31/2099
3-FKS018	Warranty Deed	2/10/1981	12/31/2099
3-FKS019	Warranty Deed	4/27/1981	12/31/2099
3-FKS020	Warranty Deed	6/29/1981	12/31/2099
3-FKS022	Warranty Deed	3/15/1982	12/31/2099
3-FKS024	Warranty Deed	6/29/1983	12/31/2099
3-FKS025	Warranty Deed	1/28/1986	12/31/2099
3-FKS027	Warranty Deed	5/21/1984	12/31/2099
3-FKS028	Warranty Deed	7/20/1984	12/31/2099
3-FKS029	Warranty Deed	7/25/1984	12/31/2099
3-FKS030	Warranty Deed	8/31/1984	12/31/2099
3-FKS031	Warranty Deed	11/2/1984	12/31/2099

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022


3-FKS032	Personal Representative Deed	11/24/1984	12/31/2099
3-FKS033	Warranty Deed	11/26/1984	12/31/2099
3-FKS034	Warranty Deed	11/30/1984	12/31/2099
3-FKS035	Warranty Deed	2/11/1985	12/31/2099
3-FKS036	Warranty Deed	2/15/1985	12/31/2099
3-FKS037	Warranty Deed	5/31/1985	12/31/2099
3-FKS038	Warranty Deed	8/8/1985	12/31/2099
3-FKS039	Warranty Deed	8/19/1985	12/31/2099
3-FKS040	Warranty Deed	12/3/1985	12/31/2099
3-FKS041	Warranty Deed	12/30/1985	12/31/2099
3-FKS042	Warranty Deed	12/30/1985	12/31/2099
3-FKS044	Warranty Deed	4/17/1986	12/31/2099
3-FKS045	Warranty Deed	6/12/1986	12/31/2099
3-FKS046	Warranty Deed	7/28/1986	12/31/2099
3-FKS047	Warranty Deed	12/19/1986	12/31/2099
3-FKS048	Warranty Deed	12/30/1986	12/31/2099
3-FKS049	Warranty Deed	6/11/1987	12/31/2099
3-FKS050	Warranty Deed	9/9/1987	12/31/2099
3-FKS051	Warranty Deed	10/30/1987	12/31/2099
3-FKS052	Warranty Deed	10/30/1987	12/31/2099
3-FKS053	Warranty Deed	1/9/1988	12/31/2099
3-FKS054	Warranty Deed	9/16/1988	12/31/2099
3-FKS055	Warranty Deed	9/16/1988	12/31/2099
3-FKS056	Warranty Deed	8/26/1989	12/31/2099
3-FKS057	Warranty Deed	8/30/1989	12/31/2099
3-FKS058	Warranty Deed	7/13/1990	12/31/2099
3-FKS059	Warranty Deed	7/13/1990	12/31/2099
3-FKS060	Warranty Deed	12/13/1991	12/31/2099
3-FKS061	Warranty Deed	12/19/1991	12/31/2099
3-FKS063	Warranty Deed	9/17/1992	12/31/2099
3-FKS064	Warranty Deed	9/17/1992	12/31/2099
3-FKS066	Warranty Deed	10/12/1993	12/31/2099
3-FKS067	Warranty Deed	10/12/1993	12/31/2099
3-FKS068	Warranty Deed	12/31/1993	12/31/2099
3-FKS069	Warranty Deed	7/12/1994	12/31/2099
3-FKS070	Warranty Deed	10/22/1994	12/31/2099
3-FKS071	Warranty Deed	11/16/1994	12/31/2099
3-FKS072	Warranty Deed	12/22/1994	12/31/2099
3-FKS073	Warranty Deed	1/9/1995	12/31/2099
3-FKS074	Warranty Deed	1/9/1995	12/31/2099
3-FKS075	Warranty Deed	1/9/1995	12/31/2099
3-FKS076	Warranty Deed	1/9/1995	12/31/2099
3-FKS077	Warranty Deed	3/28/1995	12/31/2099
3-FKS082	Warranty Deed	5/15/1995	12/31/2099
3-FKS083	Warranty Deed	6/16/1995	12/31/2099
3-FKS084	Warranty Deed	7/14/1995	12/31/2099
3-FKS085	Warranty Deed	10/27/1995	12/31/2099

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022


3-FKS086	Warranty Deed	11/15/1995	12/31/2099
3-FKS087	Warranty Deed	11/27/1995	12/31/2099
3-FKS088	Warranty Deed	12/15/1995	12/31/2099
3-FKS089	Warranty Deed	12/12/1995	12/31/2099
3-FKS090	Warranty Deed	2/16/1996	12/31/2099
3-FKS091	Warranty Deed	2/19/1996	12/31/2099
3-FKS093	Warranty Deed	5/15/1996	12/31/2099
3-FKS094	Warranty Deed	6/21/1996	12/31/2099
3-FKS095	Warranty Deed	7/15/1996	12/31/2099
3-FKS096	Warranty Deed	8/9/1996	12/31/2099
3-FKS097	Warranty Deed	8/9/1996	12/31/2099
3-FKS098	Warranty Deed	10/15/1996	12/31/2099
3-FKS099	Warranty Deed	11/27/1996	12/31/2099
3-FKS100	Warranty Deed	3/7/1997	12/31/2099
3-FKS101	Warranty Deed	3/7/1997	12/31/2099
3-FKS102	Warranty Deed	3/7/1997	12/31/2099
3-FKS103	Warranty Deed	3/7/1997	12/31/2099
3-FKS104	Warranty Deed	3/5/1997	12/31/2099
3-FKS105	Warranty Deed	1/7/1999	12/31/2099
3-FKS106	Warranty Deed	7/7/1998	12/31/2099
3-FKS107	Warranty Deed	8/14/1997	12/31/2099
3-FKS108	Warranty Deed	2/29/2000	12/31/2099
3-FKS109	Warranty Deed	1/23/2001	12/31/2099
3-FKS110	Warranty Deed	12/23/1999	12/31/2099
3-FKS111	Warranty Deed	2/24/1999	12/31/2099
3-FKS112	Warranty Deed	11/24/1999	12/31/2099
3-FKS113	Warranty Deed	3/14/2000	12/31/2099
3-FKS114	Warranty Deed	5/10/2000	12/31/2099
3-FKS115	Warranty Deed	11/8/2000	12/31/2099
3-FKS116	Warranty Deed	8/15/2001	12/31/2099
3-FKS117	Warranty Deed	8/15/2001	12/31/2099
3-FKS118	Warranty Deed	9/10/2001	12/31/2099
3-FKS119	Warranty Deed	1/14/2002	12/31/2099
3-FKS120	Warranty Deed	1/17/2002	12/31/2099
3-FKS121	Warranty Deed	2/19/2002	12/31/2099
3-FKS122	Warranty Deed	2/19/2002	12/31/2099
3-FKS123	Warranty Deed	4/18/2002	12/31/2099
3-FKS124	Warranty Deed	6/13/2002	12/31/2099
3-FKS125	Warranty Deed	12/17/2002	12/31/2099
3-FKS126	Warranty Deed	6/23/2003	12/31/2099
3-FKS127	Warranty Deed	2/20/2004	12/31/2099
3-FKS128	Warranty Deed	10/10/2003	12/31/2099
3-FKS129	Warranty Deed	4/10/2003	12/31/2099
3-FKS130	Warranty Deed	3/19/2004	12/31/2099
3-FKS131	Deed of Personal Representative	8/23/2004	12/31/2099
3-FKS132	Warranty Deed	11/10/2004	12/31/2099
3-FKS134	Warranty Deed	8/1/2006	12/31/2099

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022


3-FKS135	Warranty Deed	4/29/2005	12/31/2099
3-FKS136	Warranty Deed	5/16/2006	12/31/2099
3-FKS137	Warranty Deed	10/2/2006	12/31/2099
3-FKS138	Warranty Deed	9/29/2006	12/31/2099
3-FKS139	Warranty Deed	8/21/2006	12/31/2099
3-FKS140	Warranty Deed	9/29/2006	12/31/2099
3-FKS141	Quit Claim Deed	12/6/2005	12/31/2099
3-FKS142	Warranty Deed	5/19/2006	12/31/2099
3-FKS143	Warranty Deed	7/17/2006	12/31/2099
3-FKS144	Warranty Deed	7/18/2006	12/31/2099
3-FKS145	Trustee's Deed	9/1/2006	12/31/2099
3-FKS146	Warranty Deed	12/5/2006	12/31/2099
3-FKS147	Warranty Deed	1/24/2007	12/31/2099
3-FKS148	Warranty Deed	3/9/2007	12/31/2099
3-FKS149	Warranty Deed	3/20/2007	12/31/2099
3-FKS150	Warranty Deed	3/20/2007	12/31/2099
3-FKS151	Warranty Deed	6/15/2007	12/31/2099
3-FKS152	Warranty Deed	7/31/2007	12/31/2099
3-FKS153	Warranty Deed	8/31/2007	12/31/2099
3-FKS154	Warranty Deed	2/8/2008	12/31/2099
3-FKS155	Warranty Deed	1/23/2008	12/31/2099
3-FKS156	Warranty Deed	1/23/2008	12/31/2099
3-FKS157	Warranty Deed	4/25/2008	12/31/2099
3-FKS158	Warranty Deed	6/5/2008	12/31/2099
3-FKS159	Warranty Deed	6/16/2008	12/31/2099
3-FKS160	Warranty Deed	6/17/2008	12/31/2099
3-FKS161	Warranty Deed	1/23/2009	12/31/2099
3-FKS162	Warranty Deed	6/4/2009	12/31/2099
3-FKS163	Warranty Deed	12/17/2009	12/31/2099
3-FKS164	Warranty Deed	4/8/2010	12/31/2099
3-FKS165	Warranty Deed	5/13/2010	12/31/2099
3-FKS166	Warranty Deed	5/12/2010	12/31/2099
3-FKS167	Warranty Deed	5/12/2010	12/31/2099
3-FKS168	Warranty Deed	10/6/2010	12/31/2099
3-FKS169	Warranty Deed	11/1/2010	12/31/2099
3-FKS170	Warranty Deed	11/1/2010	12/31/2099
3-FKS171	Warranty Deed	10/29/2010	12/31/2099
3-FKS172	Warranty Deed	11/24/2010	12/31/2099
3-FKS173	Warranty Deed	12/8/2010	12/31/2099
3-FKS174	Warranty Deed	12/21/2010	12/31/2099
3-FKS175	Warranty Deed	1/27/2011	12/31/2099
3-FKS176	Warranty Deed	1/27/2011	12/31/2099
3-FKS177	Warranty Deed	4/1/2011	12/31/2099
3-FKS178	Warranty Deed	5/20/2011	12/31/2099
3-FKS179	Warranty Deed	5/15/2011	12/31/2099
3-FKS180	Warranty Deed	9/2/2011	12/31/2099
3-FKS181	Warranty Deed	12/16/2011	12/31/2099

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022


3-FKS182	Warranty Deed	12/27/2011	12/31/2099
3-FKS183	Warranty Deed	3/23/2012	12/31/2099
3-FKS184	Warranty Deed	8/31/2012	12/31/2099
3-FKS185	Warranty Deed	12/18/2012	12/31/2099
3-FKS186	Warranty Deed	4/9/2013	12/31/2099
3-FKS187	Warranty Deed	7/8/2014	12/31/2099
3-FKS188	Warranty Deed	8/15/2014	12/31/2099
3-FKS189	Warranty Deed	10/21/2014	12/31/2999
3-FKS190	Warranty Deed	12/23/2014	12/31/2099
3-FKS191	Warranty Deed	5/5/2015	12/31/2099
3-FKS192	Warranty Deed	1/6/2015	12/31/2099
3-FKS193	Warranty Deed	1/30/2015	12/31/2099
3-FKS194	Warranty Deed	8/5/2015	12/31/2099
3-FKS195	Warranty Deed	8/5/2015	12/31/2099
3-FKS196	Warranty Deed	11/4/2015	12/31/2099
3-FKS197	Warranty Deed	12/22/2015	12/31/2099
3-FKS198	Warranty Deed	12/21/2015	12/31/2099
3-FKS199	Warranty Deed	1/11/2016	12/31/2099
3-FKS200	Warranty Deed	5/13/2016	12/31/2099
3-FKS201	Warranty Deed	11/29/2016	12/31/2099
3-FKS202	Warranty Deed	12/8/2017	12/31/2099
3-FKS203	Warranty Deed	12/28/2018	12/31/2099
3-FKS204	Warranty Deed	2/14/2019	12/31/2099
3-FKS205	Warranty Deed	6/5/2019	12/31/2099
3-FKS206	Warranty Deed	11/18/2019	12/31/2099
3-FKS207	Warranty Deed	12/20/2019	12/31/2099
3-FKS208	Warranty Deed	3/9/2020	12/31/2099
3-FKS209	Warranty Deed	1/30/2020	12/31/2099

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022

MINE HISTORY, OPERATIONS AND ENCUMBRANCES

The Falkirk Mining Company (Falkirk), a subsidiary of the North American Coal Corporation (NACoal) is the owner and operator of the Falkirk Mine, an actively producing lignite surface mining operation. The Falkirk Mine generally produces between 7.2 and 8.2 million tons of lignite coal annually. All of the coal produced from the mine is delivered to Coal Creek Station (CCS).

In 1974, United Power Association (UPA) and Cooperative Power Association (CPA) announce their plans to build a 1,100-megawatt (MW) power plant on a 2,500 acre site in McLean County near the town of Underwood. North American Coal controlled reserves of over 300 million tons of lignite coal within a five-mile radius of Underwood, ND and was awarded a 35-year contract to supply coal to CCS. Falkirk has continued to supply Coal Creek Stations coal needs for over 40 years. In 2014, CCS began to deliver Falkirk coal to Spiritwood Station, located near Jamestown, ND.

The Falkirk Mine is broken out into two mine areas, the Underwood Mine Area and the Riverdale Mine Area. NACoal began initially exploring the area in the 1960s and 1970s. Based on the early drilling data, The North American Coal Corporation developed a contract with a utility to build a mine and adjacent power plant on the site. The power plant and mine facilities were located on the southern glacial channel so as to not cover up any of the coal reserve. Extensive drilling and coring programs were also initiated in 1974 and 1975 to more accurately define the coal resources of the area. Falkirk mine started to deliver coal to CCS in 1978.

The North American Coal Corporation made a lease trade with the Consolidated Coal Company (Consol) in the mid-1980s. North American gave Consol underground coal reserves in Ohio and received coal reserves in North Dakota. These North Dakota coal reserves lie immediately south-southwest of the Underwood Coal Field. The coal reserves from Consol were incorporated into the Falkirk Mine and became known as the Riverdale Coalfield. Falkirk did receive copies of all of Consol’s drilling data in the area. However, it was lacking in survey accuracy, geophysical logging, as well as known control systems. Thus, beginning in 1989, the Falkirk Mine began a drilling program to redrill all of Consol’s old drill holes and to begin completing drill hole on grids to support mining permit applications and future mine plans. Initial mining of the Riverdale Coalfield began in 1994.

Operationally, overburden and interburden removal are accomplished using scrapers, dozers, front end loaders, truck shovel fleets, and draglines. Lignite is mined with front end loaders or hydraulic backhoes, and loaded into haul trucks to transport to the stockpile or directly to the customer via truck dumps and conveyors.

Fill-in drilling programs are routinely conducted by Falkirk for the purpose of refining guidance related to ongoing operations. It is common practice at the Falkirk Mine to tighten the drilling density with-in the three to four-year block ahead of active operations to an average drill hole spacing of 1320-feet. However, additional exploration may also be scheduled in areas farther out to increase confidence in future mine plan projections.

The mine office facilities and original equipment fleets at the Falkirk Mine were constructed, acquired, or purchased new during the development stage of the mine. The facilities and equipment are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, Falkirk evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.

The total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2021 is $195.3 Million

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022

The Falkirk Mine currently has no significant encumbrances to the property. No NOVs have been issued at the Falkirk Mine in over 10 years. All permitting requirements related to surface coal mining for the projected life-of-mine (LOM) plan are currently in place.

MINERAL RESOURCES AND RESERVES

MINERAL RESOURCES

The effective date of Mineral Resource estimates is December 31, 2021.


			Quality
			Calorific Value	Moisture	Ash	Sulfur
Falkirk Mine	Resource Classification	Tonnage	(Btu/lb)	(%wt)	(%wt)	(%wt)
Underwood Field	Measured	31,599,882	6,417	40.41	7.05	0.57
	Indicated	NA	NA	NA	NA	NA
	Measured + Indicated	31,599,882	6,417	40.41	7.05	0.57
	Inferred	NA	NA	NA	NA	NA
Riverdale	Measured	46,820,901	6,614	39.44	6.37	0.58
Field	Indicated	199,721	6,317	37.10	10.69	0.73
	Measured + Indicated	47,020,623	6,612	39.43	6.39	0.58
	Inferred	NA	NA	NA	NA	NA

Total	Measured	78,420,784	6,534	39.83	6.65	0.57
	Indicated	199,721	6.317	37.10	10.69	0.73
Total	Measured+Indcated	78,620,505	6,534	39.82	6.66	0.57

Table 1.3. Mineral Resource Estimates

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022

MINERAL RESERVES

The effective date of Mineral Reserve estimates in Table 1.4 is December 31, 2021.


			Quality
			Calorific Value	Moisture	Ash	Sulfur
Falkirk Mine	Resource Classification	Tonnage	(Btu/lb)	(%wt)	(%wt)	(%wt)
Underwood	Proven	31,599,882	6,417	40.41	7.05	0.57
Field	Probable	NA	NA	NA	NA	NA
	Total	31,599,882	6,417	40.41	7.05	0.57
Riverdale	Proven	46,820,901	6,614	39.44	6.37	0.59
Field	Probable	199,721	6,317	37.10	10.69	0.73
	Total	47,020,623	6,612	39.43	6.39	0.58

Total Reserves	Proven	78,420,784	6,534	39.83	6.65	0.57
	Probable	199,721	6.317	37.10	10.69	0.73
	Total	78,620,505	6,534	39.82	6.66	0.57

Table 1.4. Mineral Reserves Estimates

DISCUSSION OF PRIOR RESOURCE AND RESERVE ESTIMATIONS

Previously, reserves for the Falkirk Mine were reported under Guide 7. All controlled tonnage that met the general mining parameters were considered for reserves. Mineral Resources were not considered. Furthermore, subcategories of Mineral Resources as measured, indicated, or inferred and Mineral Reserves as proven or probable were not considered. Table 1.5 summarizes those reported Mineral Reserves at the end of the last two fiscal years. Table 1.6. summarizes the net difference between 2021 and 2022 reported Mineral Resources and Reserves.


Report Date	Committed Tons*	Uncommitted Tons	Total Tons
1-Jan-21	370,580,372	0	370,580,372
1-Jan-20	375,689,844	0	375,689,844
*Committed tons were defined as controlled tons currently under lease ^ The difference in allotment of tons to each category from 2020 to 2021 was due to mining, lease activity, and new geologic evaluations.

Table 1.5 Summary of Prior Mineral Reserves

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022


Falkirk Mine	Tonnage
Resource Classification	1-Jan-22	1-Jan-21	Delta
Measured	78,420,784	N/A	N/A
Indicated	199,721	N/A	N/A
Measured + Indicated	78,620,505	N/A	N/A
Inferred	NA	N/A	N/A

Reserve Classification	1-Jan-22	1-Jan-21	Percent Difference
Proven	78,420,784	N/A	N/A
Probable	199,721	N/A	N/A
Total	78,620,505	370,580,372	-78.8%

Table 1.6. Net difference between 2021 and 2022 reported Mineral Resources and Reserves

Explanation of discrepancies. The majority of the discrepancy between Mineral Resources and Reserves from January 1, 2021 to the current report date is due to the TRS evaluating only tons that are within the LOM plan, which, due to the current ownership situation, was significantly reduced in scope.

Also, another cause for the variance is due to a change in methodology in categorization of Mineral Resources and Reserves from an interpretation of Guide 7 regulations to following the guidance of the Subpart S-K 1300 regulations. Tighter interpretations and guidance of the S-K 1300 regulations narrowed the basis of Mineral Resources and furthermore Mineral Reserves such that a Mineral Resource is defined as:

“A concentration or occurrence of material of economic interest in or on the Earth’s crust in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. A Mineral Resource is a reasonable estimate of mineralization, taking into account relevant factors, such as cut-off grade, likely mining dimensions, location, or continuity, that, with the assumed and justifiable technical and economic conditions, is likely to, in whole or in part, become economically extractable. It is not merely an inventory of all mineralization drilled or sampled.”

Further justification of Mineral Resources and Reserves reported herein is provided in the associated TRS for The Falkirk Mining Company.

A Mineral Reserve is defined as:

“The economically mineable part of a measured or indicated Mineral Resource, which includes diluting materials and allowances for losses that may occur when the material is mined or extracted.”

Additional impacts to the variance in reported Mineral Resources and Reserves from the January 1, 2021 report date to the January 1, 2022 report date include:

–Falkirk mined 7,882,135 tons in 2021.

–Falkirk acquired and terminated leases in 2021

SEC S-K 1300 Individual Property Disclosure

The Falkirk Mining Company 02/14/2022

MATERIAL ASSUMPTIONS FOR MINERAL RESOURCES AND MINERAL RESERVES

SEC S-K 1300 Internal Controls Disclosure

The Falkirk Mining Company 02/14/2022

EXPLORATION DRILLING - GENERAL

Independent drilling companies are contracted by The Falkirk Mining Company (Falkirk) to drill/retrieve coal cores for the Falkirk Mine. Falkirk personnel oversee the retrieval of core samples, then log and properly bag those samples for analysis by a certified third-party laboratory, Minnesota Valley Testing Laboratories, Inc. (MVTL) located in Bismarck, North Dakota.

For the purpose of this discussion, senior geologist and field geologist refer to qualified representatives of Falkirk and/or the North American Coal Corporation (NACoal).

QUALITY CONTROL AND QUALITY ASSURANCE PROGRAMS

SAMPLE PREPARATION

Upon verifying proper recovery of the core run, the field geologist succinctly, but thoroughly logs the lignite run. After the field geologist describes the core run, the entire lignite section is double bagged and tagged. Tags include the date, mine identifier, hole ID, seam ID, and “to” and “from” intervals. Double bagging preserves the moisture of the sample, and tagging on the inside bag safeguards the identification of the sample from the field through transportation to the third-party laboratory, MVTL.

A riffled split of 8-mesh coal is placed on a sample tray and weighed. The weights are sent electronically to LIMS for use in the moisture calculation. The tray is placed in an air dry oven and dried overnight. The temperature of the air dry ovens is monitored and recorded daily. The temperature monitoring devices are verified annually. Another riffled split is sealed in a Ziploc bag and retained. The client is notified prior to disposal of the coal core splits.

CONTROLS

Retained samples. Total core runs are double bagged and tagged following industry standards for quality analyses, thus split samples in the context of a retained sample are not stored at the Falkirk Mine. As such, any retained samples, including 8-mesh and 60-mesh, are stored at MVTL, and collected after total core runs have been crushed and mixed. Additionally, it is important to note that lignites tend to be high moisture coals which oxidize rapidly and do not have a long shelf life once removed from the ground. If core splits were retained at Falkirk Mine, they would not be representative of in-situ coal properties over a relatively short period of time.

SEC S-K 1300 Internal Controls Disclosure

The Falkirk Mining Company 02/14/2022

Duplicate samples. During the lab analyses MVTL runs regular control measures. For calorific value, moisture, ash, volatile matter, sulfur, ash fusion, mineral analysis of ash, carbon, hydrogen, nitrogen, mercury, and chlorine analysis, one duplicate sample is ran for every 10 samples, and a certified reference material (CRM) is analyzed at the beginning and end of each run. For sulfur forms analysis, a laboratory control sample (LCS) and one duplicate analysis is analyzed with each batch. For trace metals, a method blank, laboratory control sample (LCS) and matrix spikes are digested with each batch.

Balances. All balances are calibrated and certified annually by a third-party calibration service. Balances are verified daily using certified weights.

Round Robin Programs and Control Training. MVTL participates in round-robin testing programs with other laboratories to ensure result accuracy. MVTL participates in an Interlab Coal Round Robin Program monthly. In 2020, MVTL also participated in a lignite (coal) specific round robin program with NACoal including 8 independent laboratories, one of which was MVTL, that were used by various NACoal mine locations. The round robin consisted of four samples labeled 2001, 2002, 2003, and 2004. Two samples were sourced from Red Hills Mine and two samples were sourced from another NACoal mine, Coyote Creek Mine, located in North Dakota. The two locations provided a range of samples with variability in moisture, ash, sulfur and sodium. The labs participating in the round robin were provided 8-mesh splits and dried, 60-mesh splits of all 4 samples. The general results are summarized in Figure 1.0. MVTL is labeled “Laboratory #5”.

Figure 1.0. NACoal 2020 Round Robin Program Summary. (NACoal, 2020)

CUSTODY

Core samples remain under the supervision of the field geologist until securely stored in the mine warehouse to be shipped to the third-party laboratory, MVTL. The Falkirk Mine office and warehouse facilities are secured with user specified fob access along with 24-hour security personnel and camera surveillance.

Prior to shipping the samples, the senior geologist reviews each sample against the field records and the chain-of-custody (COC). The date, mine identifier, hole ID, seam ID, and “to” and “from” intervals are verified. A copy of the COC is emailed to the laboratory manager. Coal core samples are shipped to the third-party laboratory via insured freight with tracking information.

SEC S-K 1300 Internal Controls Disclosure

The Falkirk Mining Company 02/14/2022

Once samples are logged they are stored in the receiving room which is climate controlled (ventilation, a/c, and heat) until there is available space in the prep room; typically, a short period. Falkirk acknowledges a slight potential for moisture loss during this storage period and, as such, double bags samples in the field to preserve as much in-situ moisture as possible.

Samples are stored until they are ready to be crushed in the climate controlled prep room. There is a slight potential for moisture loss during this storage period. Falkirk acknowledges this potential and, as such, double bags samples in the field to preserve as much in-situ moisture as possible.

The building is kept secure, and all doors remained locked throughout the day, except the main customer entrance where visitors have to check in and out. No access is allowed to the laboratory without an escort. During non-operational hours the building is kept locked

Once air-drying is complete, the samples are weighed and again the weights are sent electronically to LIMS. The samples are pulverized to 60-mesh and split using a riffler. Compressed air is used to clean the pulverizer and riffler after each sample. Samples are stored in glass jars for analysis and the splits are retained in whirl-pak bags. Retained samples can be reran for analysis within 6-months for selective parameters. MVTL verifies with Falkirk prior to disposal of splits and retained samples.

QUALITY PRECISION AND ACCURACY

Prior to releasing results of requested analyses, MVTL’s reviews all analytical results for anomalies and outliers. This includes mis-type or mis-printed information, and comparison with historical coal core data on record with MVTL. Any questionable results are rerun from retained samples.

Once results are received by Falkirk, a visual inspection of results by the senior geologist is followed by a review of summary statistics with the quality of the entire drilling database. Ultimately the results are updated in the geologic model and quality grids are inspected for anomalies. At any point if questionable data is traced back to the laboratory report, the senior geologist may request the lab to rerun a retained sample.

The analytical results from the coal cores collected during Falkirk’s exploration programs have proven to be consistent with actual as-delivered quality from the active mining operations at the Falkirk Mine. This consistency is based on comparison of historical quality projected from the geologic model for the annual and monthly operating plans to actual as-delivered quality indicated by the customer’s Coal Creek Station Lab.

VERIFICATION OF ANALYTICAL PROCEDURES

The QP visited the third-party laboratory on multiple occasions over the course of the past 15 years. During the visits the laboratory manager provided a tour of the full facility from the main offices through the receiving dock/storage room, prep room, and primary laboratory. The QP noted the facility was well maintained, and clean of residue that may cause concern for contamination, including the prep room where crushing and pulverizing of materials took place. Further details about the laboratory are discussed in section 8.0 of the Technical Report Summary (TRS) for the Falkirk Mine, dated February 14th, 2022.

COMPREHENSIVE RISK INHERENT IN THE ESTIMATION OF MINERAL RESOURCES AND RESERVES

SEC S-K 1300 Internal Controls Disclosure

The Falkirk Mining Company 02/14/2022

Mine’s coalfield, The North American Coal Corporation has always used policies, protocols and procedures to ensure the accuracy and integrity of the drilling and coring data. Experienced geologists have always been on the drill rigs or supervising the engineers and/or students on the drill rigs. However, technologies and understandings change. Prior to 1976, the Falkirk Mine did not have a survey grid established. Hence, drill hole locations and elevations were read from USGS topographic quadrangle maps. Also, prior to 1975, geophysical logging on shallow coal exploration holes was not a common practice. This caused errors and deviations in locations, elevations and depths, especially as compared to more modern methods with higher levels of control. Consequently, all drilling data prior to 1976 has been deleted from Falkirk Mine’s databases and is no longer used for modeling and reserve-resource estimates. Verification of lignite quality and trends with newer drilling data has increased the confidence in the early data, but does not eliminate the inherent risk from lack of QA/QC parameters in this small percentage of data in the areas that have not been mined.

During the drilling and sampling procedure, a variety of factors could materially affect the accuracy and reliability of the results. Some examples include improper surveying of the drill hole collar location and elevation, improper and un-level drill rig set up, improper zeroing out of the elogging tool before commencing geophysical logging, not being able to obtain an elog due to collapsing drill hole conditions, not obtaining 90% recovery of the coal seam cored, allowing the coal core to be exposed for too long before bagging causing a false reduction in moisture and increase in BTU value, and improper record keeping. Most of these negative factors can be avoided by utilizing skilled and experienced drilling and elogging contractors, having proper QA/QC procedures to follow during sampling, and proper drill hole data verification.

SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine

Ackerman, Mississippi

Effective Date: December 31, 2021

Report Date: February 2, 2022

Report Prepared by:

Mississippi Lignite Mining Company

1000 McIntire Road

Ackerman, MS 39735

Signed by Qualified Persons:

Leonard Dolby, P.E.

Sara McKenzie, RPG, P.E.

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine

TABLE OF CONTENTS


SIGNATURE AND REPORT DATE			6
1.0	EXECUTIVE SUMMARY		9
		PROPERTY DESCRIPTION AND OWNERSHIP	9
		GEOLOGY AND MINERALIZATION	9
		STATUS OF EXPLORATION	10
		DEVELOPMENT AND OPERATIONS	10
		MINERAL RESOURCE ESTIMATE	10
		MINERAL RESERVE ESTIMATE	12
		ECONOMIC ASSESSMENT	13
		PERMITTING REQUIREMENTS	13
		QUALIFIED PERSON’S CONCLUSIONS AND RECOMMENDATIONS	13
2.0	INTRODUCTION		15
3.0	PROPERTY DESCRIPTION		18
	3.1	PROPERTY LOCATION	18
	3.2	PROPERTY AREA	20
	3.3	LEASES AND MINERAL RIGHTS	20
	3.4	SIGNIFICANT ENCUMBRANCES TO THE PROPERTY	28
	3.5	SIGNIFICANT FACTORS AND RISKS	28
4.0	ACCESSIBILITY, CLIMATE, LOCAL RESOURCES, INFRASTRUCTURE, AND PHYSIOGRAPHY		29
	4.1	PHYSIOGRAPHY, TOPOGRAPHY AND VEGETATION	29
	4.2	ACCESSIBILITY	29
	4.3	CLIMATE	29
	4.4	LOCAL RESOURCES AND INFRASTRUCTURE	30
5.0	HISTORY OF THE PROPERTY		31
	5.1	PREVIOUS OPERATIONS	31
	5.2	EXPLORATION AND DEVELOPMENT HISTORY PRIOR TO MLMC	31
6.0	GEOLOGICAL SETTING, MINERALIZATION AND DEPOSIT		32
	6.1	GEOLOGY	32
		REGIONAL GEOLOGY	32
		LOCAL AND PROPERTY GEOLOGY	34
6.2	MINERAL DEPOSIT TYPE		34
6.3	STRATIGRAPHIC COLUMN		35
7.0	EXPLORATION		40
	7.1	EXPLORATION	40
	7.2	DRILLING EXPLORATION	40
		DRILLING TYPE AND EXTENT	40
		GENERAL DRILLING PROCEDURES	43
		DRILLING EXPLORATION PROGRAMS	43

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine


		QUALIFIED PERSON OPINION – DRILLING EXPLORATION	46
	7.3	HYDROGEOLOGIC CHARACTERIZATION	47
		SURFACE WATER	47
		GROUNDWATER	47
		QUALIFIED PERSON OPINION – HYDROGEOLOGIC CHARACTERIZATION	48
	7.4	GEOTECHNICAL STUDIES	50
		EARLY GEOTECHNICAL STUDIES	50
		QUALIFIED PERSON OPINION – GEOTECHNICAL STUDIES	52
8.0	SAMPLE PREPARATION, ANALYSES, AND SECURITY		54
	8.1	SAMPLE COLLECTION AND SHIPMENT	54
	8.2	SAMPLE PREPARATION AND ANALYSIS	55
	8.3	QUALITY CONTROL PROCEDURES	57
	8.4	QP STATEMENT ON THE ADEQUACY OF SAMPLE PREPARATION, SECURITY AND ANALYTICAL PROCEDURES	58
9.0	DATA VERIFICATION		59
	9.1	DATA VERIFICATION PROCEDURES FOR MINERAL RESOURCES	59
		VERIFICATION OF DRILLHOLE DATA AND GEOLOGIC (MINERAL RESOURCE) MODEL	59
		VERIFICATION OF THE REASONABLE PROSPECT FOR ECONOMIC EXTRACTION TO SUPPORT MINERAL RESOURCE ESTIMATION	60
	9.2	LIMITATIONS ON DATA VERIFICATION FOR MINERAL RESOURCES	60
	9.3	QP’S STATEMENT OF ADEQUACY OF DATA FOR MINERAL RESOURCES	60
	9.4	DATA VERIFICATION PROCEDURES FOR MINERAL RESERVES	61
		VERIFICATION OF HYDROGEOLOGY DATA	61
		VERIFICATION OF GEOTECHNICAL DATA	61
		VERIFICATION OF CUT-OFF GRADE DILUTION ASSUMPTIONS AND MODIFYING FACTORS	61
		VERIFICATION OF ULTIMATE PIT CONFIGURATION	61
		VERIFICATION OF COST ESTIMATE, PRICING ASSUMPTIONS, AND ECONOMIC ANALYSIS	61
		WORKFORCE, STAFFING AND EQUIPMENT	62
		ENVIRONMENTAL FACTORS	62
	9.5	LIMITATIONS ON DATA VERIFICATION FOR MINERAL RESERVES	62
	9.6	QP’S STATEMENT OF ADEQUACY OF DATA FOR MINERAL RESERVES	62
10.0	MINERAL PROCESSING		63
11.0	MINERAL RESOURCE ESTIMATES		64
	11.1	KEY ASSUMPTIONS, PARAMETERS AND METHODS	64
		HORIZONS	64
		QUALITY PARAMETERS AND DENSITY DETERMINATION	65
		MODELING PROCESS	66
		JUSTIFICATION OF MODELING METHODS	66

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine


		LIMITS AND CONSTRAINTS ON THE MINERAL RESOURCE ESTIMATES	66
		GENERATION OF PIT SHELLS FOR MINERAL RESOURCE ESTIMATES	67
		MINERAL RESOURCE CLASSIFICATION AND UNCERTAINTY	67
	11.2	MINERAL RESOURCE ESTIMATES	71
		BASIS FOR MINERAL RESOURCE ESTIMATE	71
		MINERAL RESOURCE STATEMENT	72
	11.3	CUT-OFF QUALITY, ASSUMED COST AND SALES PRICE	72
	11.4	QP’S CLASSIFICATION OF MINERAL RESOURCES	72
	11.5	UNCERTAINTY IN THE MINERAL RESOURCE ESTIMATES	72
	11.6	QP’S OPINION ON POTENTIAL INFLUENCES AFFECTING MINERAL RESOURCE ESTIMATES	73
12.0	MINERAL RESERVE ESTIMATES		74
	12.1	KEY ASSUMPTIONS, PARAMETERS, AND METHODS	74
		STRIPPING RATIO AND PIT LIMITS	74
		LIGNITE QUALITY	74
		MODELED MINING PARAMETERS	74
		ASSUMPTIONS AND MODIFYING FACTORS	74
		METHOD	75
	12.2	MINERAL RESERVE ESTIMATES	76
		BASIS FOR MINERAL RESERVE ESTIMATE	76
	12.3	CUT-OFF QUALITY AND SALES PRICE	76
	12.4	MINERAL RESERVE STATEMENT	76
	12.5	MULTIPLE COMMODITY MINERAL RESERVE	77
	12.6	QP’s OPINION ON RISK FACTORS THAT COULD AFFECT MINERAL RESERVE ESTIMATES	77
13.0	MINING METHODS		78
	13.1	GEOTECHNICAL AND HYDROLOGICAL CONSIDERATIONS	80
		PIT DESIGN	80
		SPOIL STABILITY STUDIES	81
	13.2	LIGNITE PRODUCTION RATE, MINE LIFE, MINING DIMENSIONS AND DILUTION AND RECOVERY FACTORS	84
		PRODUCTION RATE	84
		MINE LIFE	84
		MINING DIMENSIONS	84
		MINING DILUTION	84
		RECOVERY FACTORS	85
	13.3	REQUIREMENTS FOR STRIPPING AND BACKFILLING	86
	13.4	MAJOR EQUIPMENT AND PERSONNEL	88
14.0	PROCESSING AND RECOVERY METHODS		89
15.0	INFRASTRUCTURE		90
16.0	MARKET STUDIES		92

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine


	16.1	MARKETS	92
	16.2	MATERIAL CONTRACTS	92
17.0	ENVIRONMENTAL STUDIES, PERMITTING, AND PLANS, NEGOTIATIONS, OR AGREEMENTS WITH LOCAL INDIVIDUALS OR GROUPS		93
	17.1	ENVIRONMENTAL AND BASELINE STUDIES	93
	17.2	WASTE DISPOSAL, SITE MONITORING AND WATER MANAGEMENT	93
		WASTE DISPOSAL	93
		SITE MONITORING	93
		WATER MANAGEMENT	94
	17.3	PROJECT PERMITTING REQUIREMENTS	94
		PERMIT STATUS	94
		RECLAMATION BOND REQUIREMENTS	97
	17.4	PLANS, NEGOTIATIONS, OR AGREEMENTS WITH LOCAL INDIVIDUALS OR GROUPS	97
	17.5	MINE CLOSURE PLANS	97
	17.6	QP’S OPINION OF ADEQUACY OF CURRENT PLANS	97
	17.7	DESCRIPTION OF ANY COMMITMENTS TO ENSURE LOCAL PROCUREMENT AND HIRING	97
18.0	CAPITAL AND OPERATING COSTS		98
	18.1	OPERATING COSTS	98
	18.2	CAPITAL COSTS	98
19.0	ECONOMIC ANALYSIS		99
	19.1	KEY ASSUMPTIONS, PARAMETERS AND METHODS	99
	19.2	ANNUAL CASH FLOWS	100
	19.3	SENSITIVITY ANALYSIS	100
20.0	ADJACENT PROPERTIES		102
21.0	OTHER RELEVANT DATA AND INFORMATION		103
22.0	INTERPRETATIONS AND CONCLUSIONS		104
23.0	RECOMMENDATIONS		105
24.0	REFERENCES		106
25.0	RELIANCE ON INFORMATION PROVIDED BY THE REGISTRANT		107

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine

SIGNATURE AND REPORT DATE

The effective date of this Technical Report Summary (TRS) is December 31, 2021.

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine

CERTIFICATE OF QUALIFIED PERSON LEONARD R. DOLBY

(a)At the time of signing, I am the Engineering Manager at Mississippi Lignite Mining Company’s Red Hills Mine in Ackerman, MS; a position I have held since my hire in 2017.

(b)This certificate applies to the Technical Report Summary titled, “SEC S-K 1300 Technical Report Summary, Mississippi Lignite Mining Company – Red Hills Mine, Ackerman, Mississippi.

(c)I am a Qualified Person (QP) for the purpose of SEC S-K 1300. My qualifications as a qualified person are as follows:

a.I am a graduate of the Pennsylvania State University with a Bachelor of Science in Mining Engineering in 1983.

b.I am a Professional Engineer of the state of Mississippi (License Number 28353).

c.I am a Registered Member of the Society for Mining, Metallurgy and Exploration, Inc. (SME Number 00822358).

d.My relevant experience of over 38 years, for the purpose of the Technical Report Summary, includes 11 years of mining operations experience, 10 years of consulting experience and 17 years in various technical roles, all of which have been in the coal industry.

e.As the Engineering Manager for Mississippi Lignite Mining Company’s Red Hills Mine, I conduct personal inspections of each mining area on a regular basis described in this Technical Report Summary.

f.I am responsible for the sections listed in the signature table on page 6 of this Technical Report.

g.I have read SEC S-K 1300 Technical Report Summary requirements. The part of the Technical Report Summary for which I am responsible has been prepared in compliance with this requirement.

h.At the effective date of the Technical Report Summary, to the best of my knowledge, information, and belief, the parts of the Technical Report Summary for which I am responsible, contains all scientific and technical information that is required to be disclosed to make the Technical Report Summary not misleading.

i.I consent to the filing of the Technical Report Summary as an exhibit to NACCO Industries, Inc.’s annual report. I also consent to the use of any quotes or summaries in that annual report to the extent they pertain to the Technical Report Summary sections for which I am responsible.

Dated this 2nd day of February, 2022

Leonard R. Dolby

Mississippi Lignite Mining Company

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine

CERTIFICATE OF QUALIFIED PERSON SARA T. MCKENZIE

(d)At the time of signing, I am an Engineer at the Mississippi Lignite Mining Company’s Red Hills Mine in Ackerman, MS; a position I have held since my full-time hire in 2014. From 2011 through 2014, I worked at the Red Hills Mine as an engineering intern and co-op.

(e)This certificate applies to the Technical Report Summary titled, “SEC S-K 1300 Technical Report Summary, Mississippi Lignite Mining Company – Red Hills Mine, Ackerman, Mississippi.”

(f)I am a Qualified Person (QP) for the purpose of SEC S-K 1300. My qualifications as a qualified person are as follows:

a.I am a graduate of the Missouri University of Science and Technology with a Bachelor of Science in Geological Engineering in 2014.

b.I am a Professional Engineer of the state of Mississippi (License Number 32051).

c.I am a Registered Professional Geologist of the State of Mississippi (License Number 0975).

d.My relevant experience of over 8 years including full-time and co-op experience, includes exploration, mine geology and various technical roles in the coal industry.

e.As an engineer at Mississippi Lignite Mining Company’s Red Hills Mine, I oversee the drilling exploration programs at the mine and conduct personal inspections of each mining area on a regular basis described in this Technical Report Summary.

f.I am responsible for the sections listed in the signature table on page 6 of this Technical Report.

g.I have read SEC S-K 1300 Technical Report Summary requirements. The part of the Technical Report Summary for which I am responsible has been prepared in compliance with this requirement.

Dated this 2nd day of February, 2022

Sara T. McKenzie

Mississippi Lignite Mining Company

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine

1.0 EXECUTIVE SUMMARY

This Technical Report Summary (TRS) was prepared for the Mississippi Lignite Mining Company (MLMC) to report Mineral Resources and Mineral Reserves for the Red Hill Mine in Choctaw County, Mississippi.

PROPERTY DESCRIPTION AND OWNERSHIP

The Red Hills Mine, an active lignite surface mine in Mississippi, is operated by MLMC, a wholly-owned subsidiary of North American Coal (NACoal) which is a wholly-owned subsidiary of NACCO.

MLMC is the exclusive supplier of lignite to the Red Hills Red Hills Power Plant (RHPP) in Choctaw County, Mississippi under a lignite sales agreement (LSA) with Choctaw Generation Limited Partnership (CGLP) that runs through April 2032. The RHPP supplies electricity to the Tennessee Valley Authority (TVA) under a long-term Power Purchase Agreement (PPA). CGLP leases the RHPP from a Southern Company subsidiary pursuant to a leveraged lease arrangement. The Life of Mine (LOM) plan used in this TRS report covers the period from January 2022 through April 2032 as the LOM plan assumes the RHPP will not continue to operate after the expiration of the current LSA with CGLP and the expiration of the existing PPA between TVA and CGLP in April 2032.

The Red Hills Mine is located approximately 7 miles northwest of Ackerman, Mississippi in Choctaw County, which is approximately 120 miles northeast of Jackson, Mississippi. The entrance to the mine is by means of a paved road located approximately 1 mile west of MS Highway 9.

MLMC owns in fee approximately 7,343 acres of surface interest and 4,425 acres of coal interest. MLMC holds leases granting the right to mine approximately 5,794 acres of coal interests and the right to utilize approximately 5,597 acres of surface interests. MLMC holds subleases under which it has the right to mine approximately 1,593 acres of coal interest. Most of the leases held by MLMC have terms extending 50 years, and can be further extended by the continuation of mining operations.

GEOLOGY AND MINERALIZATION

The Red Hills Mine is in the Wilcox Group of Mississippi which is the most prolific lignite-bearing stratum in the state of Mississippi. The formations within the Wilcox Group and the underlying Midway Group consist of sands, silts, clay, and lignite which were deposited during Paleogene time, approximately 66 to 23 million years ago. Deposition occurred in a cyclical manner representing a transition from a transgressive sequence of valley fill, marginal marine strata to predominantly regressive, nonmarine, deltaic strata.

During each depositional geologic sequence, organic material was repeatedly buried by sediment in an ideal, oxygen-free environment. This ideal environment was attributed to the humid, subtropical conditions and high water-table of wetlands present during Paleogene time which prevented plant matter from decaying prior to burial. The oxygen-free environment combined with heat and pressure from continual deposition of overlying sediments allowed for the formation of peat and further mineralization of lignite over time by undergoing a process known as humification and biochemical gelification.

The average thickness of the Wilcox section containing the mineable lignite seams at the Red Hills Mine and surrounding area is approximately 140 feet. Mineable lignite seams may be as thin as 1-foot and typically do not exceed 5-feet in thickness. Currently, six primary lignite seams are targeted for mining.

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine

The local structural geology for the Red Hills Mine follows the regional structure with a northwest-southeast strike dipping to the southwest. The lignite seams are gently undulating due to differential compaction of the underlying sediments.

STATUS OF EXPLORATION

Exploration programs described in this TRS have considered the stratigraphic nature of the mineralization for the determination of hole spacing, drilling and sampling method, and quality analyses in order to geologically map and evaluate the structural and quality characteristics of the lignite deposit. The Red Hills Mine lignite deposit is evaluated on a seam-by-seam basis. Drilling exploration data including geologic lithologies, qualities, and hole locations have been compiled in an electronic, geologic database.

From 1975 through 1980 drilling campaigns were completed under the sole direction of Phillips Coal Company (Phillips). Since 1997, independent drilling and geophysical logging contractors have operated under the guidance and direction of MLMC.

Over 1,400 drill holes including pilot holes, coal core holes, overburden holes, geotechnical holes, and monitoring wells have been drilled within the Red Hills Mine lignite deposit. Drilling campaigns conducted at the mine have comprised largely of rotary wash drilling methods. Drill holes were geophysically logged for natural gamma, density, caliper, and resistivity responses to obtain data related to the subsurface structure. Coal core samples collected for quality analyses were sent to independent commercial laboratories for testing.

DEVELOPMENT AND OPERATIONS

The Red Hills Mine is a multiple lignite seam surface mining operation which supplies approximately 2.6 to 3.2 million tons of lignite per year to the adjacent RHPP. Actual annual production is dictated by customer demand. The RHPP supplies electricity to TVA under a long-term PPA. MLMC's customer's demand for coal is driven by the decision of which power plants to dispatch as determined by TVA. An increase in the number of days TVA dispatches the RHPP would increase demand. A decrease in the number of days TVA dispatches the RHPP would reduce demand.

The lignite at the Red Hills Mine surface mining operation is uncovered using dragline, dozer, and conventional truck and shovel mining methods due to the proximity of the lignite to the surface and the physical characteristics of the deposit. Lignite is mined using a surface miner or a hydraulic backhoe to load a fleet of end dump haul trucks and is directly shipped to the RHPP or the lignite stockpile. The overall average Run of Mine (ROM) quality of the mined lignite seams meets the required power plant quality specifications. Therefore, no mineral processing is performed by MLMC.

The Red Hills Mine began operations in the MS-002 permit area in Mine Area 1 and is in the process of transitioning to Mine Area 3 within the MS-004 permit area. Initial development of the Red Hills Mine began in 1998, with full production and commercial deliveries commencing in 2002. Boxcut construction for Mine Area 3 began in 2021 where mining will continue through April 2032. The Red Hills Mine has, or is currently constructing, all supporting infrastructure for mining operations within the permitted areas.

The Red Hills Mine employs a staff and workforce of approximately 200 employees with fluctuations in employment levels for changes in demand at the RHPP or special projects such as the transition of mining from Mine Area 1 to Mine Area 3.

MINERAL RESOURCE ESTIMATE

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine

The QP based the Mineral Resource estimates for the Red Hills Mine on a stratigraphic geologic model generated from the verified drilling exploration data. For a lignite seam to be considered a Mineral Resource by the QP, the seam must have a minimum of ten coal core samples for quality estimation, and an average coal core quality which fell within the quality limits set forth by the LSA. Mineral Resources were then further defined for each identified lignite seam by applying projected pit shells based on physical constraints, including but not limited to lease and fee coal boundaries, and a maximum cumulative stripping ratio of 18:1 based on an assumed lignite sales price of $30 per ton.

Mineral Resources were divided into three categories of Measured, Indicated, or Inferred and were ranked by increasing level of confidence. The Mineral Resource categorization applied by the QP included the consideration of the type and amount of data per drill hole and the spatial distribution of drill holes. Measured Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the distance from a core hole is less than or equal to 1,000 feet. Indicated Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the distance from a core hole is greater than 1,000 feet and less than or equal to 3,000 feet. Inferred Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the distance from a core hole is greater the 3,000 feet.

Mineral Resources as of December 31, 2021 are shown in Table 1.1, and are reported as in-situ tons such that no adjustments were made to account for mining recovery or losses. Mineral Resources are reported exclusive of in-situ Mineral Reserves.

Table 1.1. Mineral Resource Estimates.

In the opinion of the QP it is important to note that additional exploration may positively or negatively affect Mineral Resource estimates. Additionally, Mineral Resource estimates may be materially affected by a change in the assumptions including general mining costs and land control. New regulations may also impose additional economic factors, delays to future permit renewals, or restrictions to physical estimation boundaries.

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine

At the time of this TRS, the QP is not aware of any specific factors that would materially affect the Mineral Resource estimates presented herein.

MINERAL RESERVE ESTIMATE

Parameters for mining dilution, minimum mining thickness, and minimum parting thickness were applied by the QP to the geologic (Mineral Resource) model to create the Mineral Reserve model. Mining pits were projected based on current mining equipment operating parameters and a maximum cumulative stripping ratio of 14:1 based on an estimated average price per ton of $28.04. Mining pits were then sectioned into 500-foot blocks; adjusting endwall blocks as necessary. Blocks were reviewed by the QP to ensure quality thresholds were met. Recovery rates were applied to the lignite tonnages by seam and then the blocks were sequenced based on a projected total delivered heat requirement measured in million British Thermal Units (MMBtu) through the LOM plan to determine the Measured Resources that would be converted to Mineral Reserves.

This disclosure of Mineral Reserves is based upon the QP’s opinion that the LOM plan and cost estimates have been completed to a Pre-feasibility (PFS) level of accuracy, as defined in 17 Code of Federal Regulations (CFR) Part 229.1300, which includes and supports the QP’s determination of Mineral Reserves.

The Red Hills Mine Mineral Reserve, as of December 31, 2021, is shown in Table 1.2.

Table 1.2. Mineral Reserve Estimates.

The QP’s opinion on risks related to Mineral Reserve estimates include changes in customer demand for any reason, including, but not limited to, dispatch of power generated by other energy sources ahead of coal, fluctuations in demand due to unanticipated weather conditions, regulations or comparable policies which may promote planned and unplanned outages at the RHPP, economic conditions, including an economic slowdown and a corresponding decline in the use of electricity, governmental regulations and/or inflationary adjustments which could have a material adverse effect on MLMC's financial condition, results of operations and cash flows.

At the time of this TRS, the QP is not aware of any specific factors that would materially affect the Mineral Reserve estimates.

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine

ECONOMIC ASSESSMENT

The primary driver in determining the economic viability of the Red Hills Mine was the expected annual operating performance of the RHPP, which was forecasted using two main inputs: the annual projection notice (nomination for MMBtu requirements) received from the RHPP and a comparison to historical prior years actual delivered lignite fuel. The annual MMBtu requirement used in the Red Hills LOM Economic Model was 27,215,000 MMBtu. This resulted in a production schedule of approximately 2.7 million tons (Mt) of dedicated lignite per year each year until LSA contract expiration in April 2032.

LOM operating costs for a plan delivering 27,215,000 MMBtu per year to the RHPP total approximately $830 million (M). Operating costs included major cost categories for mine development, burden removal, severing of lignite, reclamation, maintenance and handling of stockpiled lignite and delivery to the adjacent RHPP along with the necessary maintenance required to keep all equipment operating safely and efficiently.

Capital costs to fulfill the LSA for a plan delivering 27,215,000 MMBtu per year to the RHPP are expected to total approximately $32 M. Capital Costs included categories for equipment expenditures, mine development, mitigation, and land acquisitions.

The base price for the dedicated lignite is defined in the LSA and consists of eight indexed components including a power cost component, a pass-through component, a royalty component and a fixed component. Over the LOM plan, the average price per ton for lignite delivered and sold is $28.04 providing revenues totaling approximately $769 M.

The projected annual cash flow forecast based on the lignite production schedule over the remaining LOM results in a total after-tax cash flow projection of $80 M resulting in a net present value of $42 M at a 10% discount rate.

The Economic Assessment used what could be considered a conservative assumption in light of historical trends, current conditions and expected future developments for delivered fuel to the RHPP of 27,215,000 MMBtu annually. Therefore, the QP is of the opinion that any downside risks to the economic viability of the project to be minimal. There is a risk to the LOM plan if the RHPP takes less than the LOM plan MMBtu’s, but this scenario is not considered a significant risk as a result of the minimum take provisions included in the LSA. Other downside risks modeled were the effects of an increase in diesel prices and labor.

PERMITTING REQUIREMENTS

The Red Hills Mine operates under the state of Mississippi Surface Coal Mining and Reclamation Permit MS-002, Renewal 3 and Surface Coal Mining and Reclamation Permit MS-004 issued by the Mississippi Department of Environmental Quality (MDEQ) under delegated authority of the United States Department of the Interior, Office of Surface Mining Reclamation Enforcement (OSMRE) Surface Mining Control and Reclamation Act (SMCRA). In addition to the mining permit, MLMC has secured 45 other permit and agreements, including a National Pollutant Discharge Elimination System (NPDES) permit and an Individual Permit issued by the United States Army Corp of Engineers (USCOE). All permits have been secured and continue to be renewed in a timely fashion.

MLMC currently has all permits in place for the Red Hills Mine to operate and adhere to a mine plan projected through April 2032. Barring any regulatory changes out of MLMC’s control, the QP does not anticipate hurdles for approval of future renewal applications.

QUALIFIED PERSON’S CONCLUSIONS AND RECOMMENDATIONS

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine

material misrepresentations for the statements of Mineral Reserves. There are currently no recommendations for Mineral Reserves.

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine

2.0 INTRODUCTION

This Technical Report Summary (TRS) was prepared for the Mississippi Lignite Mining Company (MLMC), a wholly-owned subsidiary of the North American Coal Corporation (NACoal) which is a wholly-owned subsidiary of NACCO.

The purpose for which this TRS was prepared is to report Mineral Resources and Mineral Reserves for the Red Hill Mine located in Choctaw County, Mississippi.

The sources of information and data contained in the technical report or used in its preparations were supplied by MLMC and include data used to produce geologic models, Annual and Life of Mine (LOM) plans, production data, environmental support documents, independent technical studies, resource and reserve estimates, cost estimates, and economic analyses. A large portion of the technical information is summarized from active Surface Mining Control and Reclamation Act (SMCRA) permits addressing Title 11 of the Miss. Admin. Code Pt.8, Ch-2, Mississippi Commission on Environmental Quality Regulations Governing Surface Coal Mining, hereby known as the mine permit requirements. Additional references to specific studies and documents are provided in Section 24.0 of this TRS.

Qualified Persons (QPs) are employed by MLMC. As such, inspections of the Red Hills Mine are conducted to perform the duties of their respective jobs on a regular basis and no individual date of inspection has been identified. Sara T. McKenzie is serving as the Mineral Resource QP, a Registered Professional Geologist and licensed Professional Engineer, who has direct oversight of the drilling exploration programs, and is directly involved in mine development projects and daily production operations at the Red Hills Mine. Leonard R. Dolby, is serving as the Mineral Reserve QP, a licensed Professional Engineer and registered SME member, who has direct engagement with daily production operations and oversight and management of technical projects as the Engineering Manager, and is directly involved in the development of the LOM finances at the Red Hills Mine.

This is the first TRS filed to the United States Securities and Exchange Commission (SEC) therefore no preexisting TRS exists with the SEC.

Unless otherwise stated, the terms of reference for this TRS include:

–US English spelling;

–Imperial units of measurement;

–Lignite qualities are presented in weight percent (wt%) and lignite tonnages are present in short tons (2000 lbs);

–Coordinate System is presented in imperial units using the North American Datum 1983 (NAD83), Mississippi East State Plane;

–Nominal US Dollars as of 2021.

Key Acronyms and definitions for this TRS include:


AOP			Annual Operating Plan
AR			As-Received Basis
ARO			Asset Retirement Obligation
ASTM			American Society for Testing and Materials
BCY			Bank Cubic Yard
BMPs			Best Management Practices
BOX			Base of Oxidation
BUD			Beneficial (Ash) Use Determination

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine


Cardno GLS			Cardno Geophysical Logging Services
Century GLS CGLP			Century Geophysical Logging Services Choctaw Generation Limited Partnership
COC			Chain of Custody
CRIRSCO			Committee for Mineral Reserves International Reporting Standards
DMRs			Discharge Monitoring Reports
DTM			Digital Terrain Model
EIS			Environmental Impact Statement
FoS			Factor of Safety
GEA			Geotechnical Engineering Associates
gpm			Gallons per Minute
GSE HDPE			Great Southern Engineering High Density Polyethylene
Lbs			Pounds
LOM			Life of Mine
LSA M			Lignite Sales Agreement Million (dollars)
MA1			Mine Area 1
MA3			Mine Area 3
MDA&H			Mississippi Department of Archives and History
MDEQ			Mississippi Department of Environmental Quality
MDOT			Mississippi Department of Transportation
MLMC MMbtu			The Mississippi Lignite Mining Company Metric Million British Thermal Units
MS-002 permit			Surface Mining Control and Reclamation Act (SMCRA) permit MS-002, Renewal 3
MS-004 permit			Surface Mining Control and Reclamation Act (SMCRA) permit MS-004
mg/L			Milligrams per Liter
msl			Mean Sea Level
Mt			Million Tons
MSU			Mississippi State University
MS NACCO			Mississippi NACCO Industries

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine


NACoal			North American Coal
NOV			Notice of Violation
NPDES			National Pollutant Discharge Elimination System
NPS			National Park Service
NRCS			Natural Resources Conservation Service
OSMRE			United States Department of the Interior, Office of Surface Mining Reclamation Enforcement
Phillips Prox PPA QAR PTP			Phillips Coal Company Proximate Power Purchase Agreement Proficiency Testing Program by Quality Assurance Resources, LLC
QA/QC			Quality Assurance/Quality Control
QP(s)			Qualified Person(s)
RHPP			Red Hills Power Plant
R-O-M			Run of Mine
R-O-W			Right of Way
SEC			United States Security and Exchange Commission
SG			Specific Gravity
S-K 1300 SMCRA			SEC’s Subpart S-K 1300 (17 CFR Part 229.1300) Surface Mining Control and Reclamation Act
SPGM			Suitable Plant Growth Material
SPT			Standard Penetration Testing
SWPPP			Storm Water Pollution and Prevention Plan
TDS			Total Dissolved Solids
TRS			Technical Report Summary
TSS			Total Suspended Solids
TVA USCOE			the Tennessee Valley Authority United States Corps of Engineers
USCS			Unified Soil Classification System
USGS			United States Geological Survey
WOTUS			Waters of the United States

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine

3.0 PROPERTY DESCRIPTION

3.1 PROPERTY LOCATION

The Red Hills Mine is an operating lignite surface mine located approximately 7 miles northwest of Ackerman, Mississippi, in Choctaw County, which is approximately 120 miles northeast of Jackson, Mississippi. The entrance to the mine is by means of a paved road that is located approximately 1 mile west of MS Highway 9. The general location of the Red Hills Mine is shown in Figure 3.1 (Location of Red Hills Mine). The RHPP is adjacent to the Red Hills Mine.

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine

Figure 3.1. Location of the Red Hills Mine.

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine

3.2 PROPERTY AREA

The Red Hills Mine is encompassed by two permit areas, MS-002 and MS-004 as indicated in Figure 3.1. Two Mineral Resource areas fall within the MS-002 permit area, and are identified as Mine Area 1 and Mine Area 2. A third Mineral Resource area falls within the MS-004 permit area, and is identified as Mine Area 3. Mine Area 1 and Mine Area 3 include Mineral Reserves in addition to Mineral Resources. Mine Area 2 is a small, permitted auxiliary pit which may be used for tons to supplement the mine plan, but is not currently sequenced in the LOM plan, and as such only includes Mineral Resources, not Mineral Reserves. Mine Area 1 is 356 acres, Mine Area 2 is 202 acres, and Mine Area 3 is 2,197 acres.

MLMC holds leases granting the right to mine approximately 5,794 acres of coal interests and the right to utilize approximately 5,597 acres of surface interests. In addition to leases with independent landowners, MLMC owns in fee approximately 7,343 acres of surface interest and 4,425 acres of coal interest. MLMC holds subleases under which it has the right to mine approximately 1,593 acres of coal interest.

3.3 LEASES AND MINERAL RIGHTS

The name or number and expiration date of each title, claim, mineral right, lease, or option under which MLMC or an affiliated NACCO company has or will have the right to hold or operate on the property is described on Table 3.1 (Identification of Leases) and Table 3.2 (Identification of Acquisitions).

The leases, sub-leases and fee acquisitions were obtained by land acquisition staff employed by Phillips and NACoal. Most of the leases held by MLMC have terms extending 50 years, and can be further extended by the continuation of mining operations. The surface and mineral leases and associated sub-leases held by MLMC require payments specified by lease agreement to retain the property. Typically, a standard production royalty rate of $0.50 per ton of lignite mined is tied to the leases. Royalties are calculated monthly based on surveyed mined tons and are paid to the landowners on a quarterly basis. In addition to production royalties, payments related to landowner leases may also include surface damage payments and/or advanced royalties.


Table 3.1. Identification of Leases
Lease Id	Lease Type	Lease Date	Lease Expiration Date
955-900002	Coal Lease	12/31/2013	12/30/2038
955-900003	Coal Lease	12/31/2013	12/30/2038
955-900004	Coal Lease	12/31/2013	12/30/2038
955-900005	Coal Lease	12/31/2013	12/30/2038
955-900006	Coal Lease	12/31/2013	12/30/2038
955-900007	Coal Lease	12/31/2013	12/30/2038
955-900008	Coal Lease	12/31/2013	12/30/2038
955-900009	Coal Lease	12/31/2013	12/30/2038
955-900010	Coal Lease	12/31/2013	12/30/2038
955-900011	Coal Lease	12/31/2013	12/30/2038
955-900012	Coal Lease	12/31/2013	12/30/2038
955-900013	Coal Lease	12/31/2013	12/30/2038
955-900014	Coal Lease	12/31/2013	12/30/2038
955-900015	Coal Lease	12/31/2013	12/30/2038
955-900016	Coal Lease	12/31/2013	12/30/2038
955-900017	Coal Lease	12/31/2013	12/30/2038
955-900018	Coal Lease	12/31/2013	12/30/2038
955-900019	Coal Lease	12/31/2013	12/30/2038
955-900023	Coal Lease	7/10/2015	7/9/2040
955-900024	Coal Lease	7/10/2015	7/9/2040

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine


955-900025	Coal Lease	7/10/2015	7/9/2040
955-900026	Coal Lease	7/10/2015	7/9/2040
955-900027	Coal Lease	7/10/2015	7/9/2040
955-900028	Coal Lease	7/10/2015	7/9/2040
955-900029	Coal Lease	7/10/2015	7/9/2040
955-900030	Coal Lease	10/26/2015	10/25/2040
955-900031	Coal Lease	10/26/2015	10/25/2040
955-900032	Coal Lease	5/6/2016	5/5/2041
955-900033	Coal Lease	10/1/2017	9/30/2042
955-900038	Coal Lease	6/1/2019	5/31/2044
956-929484	Coal Lease	5/9/1975	5/8/2025
956-929485	Coal Lease	5/9/1975	5/8/2025
956-929508	Coal Lease	5/14/1975	5/13/2025
956-929557	Coal Lease	5/13/1975	5/12/2025
956-929588	Coal Lease	3/5/1981	3/4/2031
956-929589	Coal Lease	6/16/1975	6/15/2025
956-929597	Coal Lease	6/24/1975	6/23/2025
956-929599	Coal Lease	5/12/1975	5/11/2025
956-929603	Coal Lease	6/26/1975	6/25/2025
956-929646	Coal Lease	6/2/1975	6/1/2025
956-929743	Coal Lease	5/14/1975	5/13/2025
956-929744	Coal Lease	6/11/1975	6/10/2025
956-929745	Coal Lease	6/11/1975	6/10/2025
956-929748	Coal Lease	5/22/1978	5/21/2028
956-929749	Coal Lease	8/7/1975	8/6/2025
956-929750	Coal Lease	8/4/1975	8/3/2025
956-929751	Coal Lease	6/17/1975	6/16/2025
956-929752	Coal Lease	6/5/1975	6/4/2025
956-929755	Coal Lease	8/7/1975	8/6/2025
956-929757	Coal Lease	8/25/1975	8/24/2025
956-929759	Coal Lease	8/27/1975	8/26/2025
956-929801	Coal Lease	10/24/1974	10/23/2025
956-929802	Exploration Contract & Coal Lease	10/30/1974	10/29/2025
956-929803	Coal Lease	9/4/1975	9/3/2025
956-929835	Exploration Contract & Coal Lease	10/24/1974	10/23/2025
956-929839	Coal Lease	9/15/1975	9/14/2025
956-929841	Coal Lease	9/15/1975	9/14/2025
956-929842	Coal Lease	9/24/1975	9/23/2025
956-929910	Exploration Contract & Coal Lease	10/11/1974	10/10/2025
956-929911	Exploration Contract & Coal Lease	10/28/1974	10/27/2025
956-929954	Coal Lease	9/22/1975	9/21/2025
956-929955	Coal Lease	9/25/1975	9/24/2025
956-929956	Coal Lease	9/26/1975	9/25/2025
956-929957	Coal Lease	9/20/1975	9/19/2025
956-929958	Coal Lease	10/2/1975	10/1/2025
956-929959	Coal Lease	10/3/1975	10/2/2025
956-930068	Coal Lease	10/13/1975	10/12/2025
956-930187	Coal Lease	10/7/1975	10/6/2025

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine


956-930280	Coal Lease	12/18/1975	12/17/2025
956-930367	Coal Lease	12/16/1975	12/15/2025
956-930413	Coal Lease	2/27/1976	2/26/2026
956-930414	Coal Lease	2/27/1976	2/26/2026
956-930474	Coal Lease	1/26/1976	1/25/2026
956-930480	Coal Lease	2/3/1976	2/2/2026
956-930482	Coal Lease	2/25/1976	2/24/2026
956-930483	Coal Lease	2/19/1976	2/18/2026
956-930488	Coal Lease	3/18/1976	3/17/2026
956-930493	Coal Lease	3/10/1976	3/9/2026
956-930494	Coal Lease	3/17/1976	12/31/2036
956-930495	Coal Lease	3/22/1976	3/21/2026
956-930497	Coal Lease	3/23/1976	3/22/2026
956-930499	Coal Lease	3/18/1976	3/17/2001*
956-930500	Coal Lease	3/8/1976	3/7/2026
956-930501	Coal Lease	3/31/1976	3/30/2026
956-930513	Coal Lease	4/21/1976	4/20/2026
956-930514	Coal Lease	4/21/1976	4/20/2026
956-930515	Coal Lease	4/13/1976	4/12/2026
956-930516	Coal Lease	5/1/1976	4/30/2026
956-930530	Coal Lease	5/4/1976	5/3/2026
956-930593	Coal Lease	3/16/1976	3/15/2026
956-931123	Coal Lease	4/11/1978	4/10/2028
956-931124	Coal Lease	4/11/1978	4/10/2028
956-931250	Coal Lease	8/14/1978	8/13/2028
956-931266	Coal Lease	1/19/1983	1/18/2008*
956-931267	Coal Lease	1/21/1983	1/20/2008*
956-931308	Coal Lease	6/25/1980	6/24/2030
956-931314	Coal Lease	7/31/1980	7/30/2030
956-931316	Coal Lease	8/12/1980	8/11/2030
956-931317	Coal Lease	9/11/1980	9/10/2030
956-931318	Coal Lease	9/18/1980	9/17/2030
956-931323	Coal Lease	10/8/1980	10/7/2030
956-931395	Coal Lease	7/29/1981	7/28/2031
956-931396	Coal Lease	8/24/1981	8/23/2031
956-931397	Coal Lease	8/24/1981	8/23/2031
956-931398	Coal Lease	2/10/1982	2/9/2032
956-931409	Coal Lease	7/31/1981	7/30/2031
956-931473	Coal Lease	3/25/1982	3/24/2032
956-931474	Coal Lease	3/25/1982	3/24/2032
956-931475	Coal Lease	4/9/1982	4/8/2032
956-931476	Coal Lease	6/28/1982	6/27/2032
956-931477	Coal Lease	6/8/1982	6/7/2032
956-931478	Coal Lease	6/28/1982	6/27/2032
956-931479	Coal Lease	12/2/1982	12/1/2032
956-931480	Coal Lease	12/2/1982	12/1/2032
956-931481	Coal Lease	3/25/1982	3/24/2032
956-931484	Coal Lease	5/10/1982	5/9/2032

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine


956-931485	Coal Lease	5/10/1982	5/9/2032
956-931524	Coal Lease	10/8/1982	10/7/2032
956-931537	Coal Lease	12/13/1982	12/12/2032
956-931577	Coal Lease	5/3/1983	5/2/2008*
956-931579	Coal Lease	5/2/1983	5/1/2008*
956-931640	Coal Lease	7/2/1997	7/1/2047
956-931641	Coal Lease	7/2/1997	7/1/2047
956-931642	Coal Lease	7/11/1997	7/10/2047
956-931643	Coal Lease	7/18/1997	7/17/2047
956-931644	Coal Lease	7/2/1997	7/1/2047
956-931645	Coal Lease	7/2/1997	7/1/2047
956-931646	Coal Lease	7/2/1997	7/1/2047
956-931647	Coal Lease	7/11/1997	7/10/2047
956-931648	Coal Lease	7/18/1997	7/17/2047
956-931649	Coal Lease	7/2/1997	7/2/2047
956-931658	Coal Lease	11/23/1999	11/22/2024
956-931677	Coal Lease	5/17/2000	5/16/2050
956-931705	Coal Lease	7/16/2001	7/15/2026
956-931706	Coal Lease	10/6/2005	10/5/2030
956-931708	Coal Excavation Lease	12/10/2007	12/9/2047
956-931709	Coal Lease	3/22/2010	3/21/2035
956-931710	Coal Lease	5/25/2011	5/24/2061
956-931711	Coal Lease	12/20/2012	12/19/2062
956-931712	Coal Lease	12/17/2012	12/16/2062
956-931713	Coal Lease	12/20/2012	12/19/2062
956-931714	Coal Lease	9/11/2013	9/10/2063
956-931716	Coal Lease	12/20/2013	12/19/2063
956-931718	Lignite Mining Lease	9/25/2013	9/24/2063
956-931719	Coal Lease	12/20/2013	12/19/2063
956-931723	Coal Lease	4/19/2016	4/18/2066
956-931724	Coal Lease	9/9/2016	9/8/2066
956-931728	Coal & Lignite Lease Agreement	11/14/2017	11/13/2047
956-931729	Coal Lease	11/16/2017	11/15/2067
956-931730	Lignite Mining Lease	12/18/2017	12/17/2067
956-931734	Coal Lease	9/28/2018	9/27/2043
956-931735	Coal Lease	1/23/2019	1/22/2044
956-931737	Coal Lease	3/13/2019	3/12/2069
956-931738	Coal Strip Mining Lease	10/25/2019	10/24/2034
956-931742	Coal Lease	1/31/2021	1/30/2071
956-931743	Coal Lease	6/25/2021	6/24/2071
*Lease continued past expiration by annual payment.

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine


Table 3.2. Identification of Acquisitions
Agreement Id	Agreement Type	Agreement Date	Agreement Expiration Date
957-MLC001	Warranty Deed	8/19/1998	8/18/2097
957-MLC002	Coal Warranty Deed	10/1/1997	12/31/2099
957-MLC003	Warranty Deed	9/17/1998	9/16/2097
957-MLC004	Warranty Deed	12/22/2000	12/21/2999
957-MLC005	Warranty Deed	9/20/2001	9/19/2100
957-MLC006	Warranty Deed	10/12/1998	12/31/2099
957-MLC007	Warranty Deed	10/1/2001	9/30/2100
957-MLC008	Warranty Deed	1/22/2002	1/21/2101
957-MLC009	Warranty Deed	1/22/2002	1/21/2101
957-MLC010	Warranty Deed	10/29/1996	10/28/2096
957-MLC011	Warranty Deed	6/1/1999	6/1/2099
957-MLC012	Warranty Deed	1/5/1999	1/5/2098
957-MLC013	Coal and Lignite Deed	7/8/2005	7/7/2104
957-MLC014	Special Warranty Deed	4/2/1998	4/1/2097
957-MLC015	Special Warranty Deed	8/11/1998	8/10/2097
957-MLC016	Warranty Deed	9/5/1998	12/31/2099
957-MLC017	Warranty Deed	1/24/2000	1/24/2099
957-MLC018	Warranty Deed	8/19/1998	8/19/2097
957-MLC019	Warranty Deed	1/24/2000	1/23/2099
957-MLC020	Warranty Deed	8/17/1998	8/16/2098
957-MLC021	Warranty Deed	6/30/1998	6/29/2097
957-MLC022	Warranty Deed	3/11/1998	3/10/2098
957-MLC023	Warranty Deed	2/25/2003	2/24/2102
957-MLC024	Warranty Deed	11/10/1998	11/9/2097
957-MLC025	Warranty Deed	11/24/1998	11/23/2097
957-MLC026	Warranty Deed	5/14/1999	5/13/2098
957-MLC027	Warranty Deed	4/8/1999	4/7/2098
957-MLC028	Warranty Deed	4/22/1999	4/22/2999
957-MLC029	Warranty Deed	7/7/1999	7/6/2098
957-MLC030	Warranty Deed	5/2/2003	5/1/2102
957-MLC031	Warranty Deed	5/5/2003	5/4/2102
957-MLC032	Warranty Deed	5/2/2003	5/1/2102
957-MLC033	Warranty Deed	7/8/2003	7/7/2102
957-MLC034	Warranty Deed	3/17/2004	12/31/2099
957-MLC035	Warranty Deed	7/16/2004	7/15/2103
957-MLC036	Warranty Deed	11/15/2004	12/31/2999
957-MLC037	Warranty Deed	2/18/2005	12/31/2999
957-MLC038	Warranty Deed	2/23/2005	2/22/2104
957-MLC039	Warranty Deed	4/8/2005	4/7/2104
957-MLC040	Warranty Deed	2/28/2006	2/27/2105
957-MLC041	Warranty Deed	6/28/2007	6/28/2106
957-MLC042	Warranty Deed	7/26/2006	7/25/2105
957-MLC043	Warranty Deed	10/28/2006	10/27/2105
957-MLC044	Warranty Deed	10/28/2006	10/27/2105

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine


957-MLC045	Warranty Deed	10/27/2006	10/26/2105
957-MLC046	Warranty Deed	8/1/2007	7/31/2106
957-MLC047	Warranty Deed	11/20/2007	11/19/2106
957-MLC048	Special Warranty Deed	11/7/2007	11/6/2106
957-MLC049	Warranty Deed	11/26/2007	11/25/2106
957-MLC050	Warranty Deed	6/13/2008	12/31/2099
957-MLC051	Warranty Deed	9/4/2008	12/31/2099
957-MLC052	Warranty Deed	4/23/2009	12/31/2999
957-MLC053	Warranty Deed	12/21/2010	12/31/2999
957-MLC054	Warranty Deed	5/25/2011	12/31/2999
957-MLC055	Special Warranty Deed	6/27/2011	12/31/2999
957-MLC056	Special Warranty Deed	7/3/2011	12/31/2999
957-MLC057	Special Warranty Deed	7/8/2011	12/31/2999
957-MLC058	Warranty Deed	10/13/2011	12/31/2999
957-MLC059	Warranty Deed	10/13/2011	12/31/2999
957-MLC060	Warranty Deed	12/30/2011	12/31/2999
957-MLC061	Warranty Deed	7/17/2012	12/31/2099
957-MLC062	Warranty Deed	7/13/2012	12/31/2099
957-MLC063	Warranty Deed	7/13/2012	12/31/2099
957-MLC064	Warranty Deed	9/20/2012	12/31/2099
957-MLC065	Warranty Deed	12/6/2012	12/31/2999
957-MLC066	Warranty Deed	12/6/2012	12/31/2099
957-MLC067	Warranty Deed	12/3/2012	12/31/2099
957-MLC068	Warranty Deed	4/3/2013	12/31/2099
957-MLC069	Warranty Deed	12/20/2012	12/31/2099
957-MLC070	Warranty Deed	12/17/2012	12/31/2099
957-MLC071	Warranty Deed	12/14/2012	12/31/2099
957-MLC072	Warranty Deed	12/14/2012	12/31/2099
957-MLC073	Warranty Deed	12/20/2012	12/31/2099
957-MLC074	Warranty Deed	12/20/2012	12/31/2099
957-MLC075	Warranty Deed	10/5/2012	12/31/2099
957-MLC076	Warranty Deed	4/3/2013	12/31/2099
957-MLC077	Warranty Deed	5/3/2013	12/31/2099
957-MLC078	Warranty Deed	6/13/2013	12/31/2999
957-MLC079	Warranty Deed	6/14/2013	12/31/2099
957-MLC080	Warranty Deed	9/11/2013	12/31/2099
957-MLC081	Special Warranty Deed	12/31/2013	12/31/2999
957-MLC082	Special Warranty Deed	12/31/2013	12/31/2099
957-MLC084	Warranty Deed	12/20/2013	12/31/2099
957-MLC085	Quit Claim Deed	7/10/2015	12/31/2099
957-MLC086	Quit Claim Deed	7/10/2015	12/31/2999
957-MLC087	Quit Claim Deed	7/10/2015	12/31/2099
957-MLC088	Warranty Deed	12/20/2013	12/31/2999
957-MLC089	Quit Claim Deed	7/10/2015	12/31/2099
957-MLC091	Quit Claim Deed	7/10/2015	12/31/2099
957-MLC092	Quit Claim Deed	7/10/2015	12/31/2099
957-MLC094	Quit Claim Deed	7/10/2015	12/31/2099
957-MLC095	Quit Claim Deed	7/10/2015	12/31/2099

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine


957-MLC096	Quit Claim Deed	10/26/2015	12/31/2099
957-MLC097	Quit Claim Deed	10/26/2015	12/31/2099
957-MLC098	Quit Claim Deed	10/26/2015	12/31/2099
957-MLC099	Quit Claim Deed	5/6/2016	12/31/2099
957-MLC100	Quit Claim Deed	9/1/2016	12/31/2099
957-MLC101	Quit Claim Deed	9/1/2016	12/31/2099
957-MLC102	Quit Claim Deed	9/1/2016	12/31/2099
957-MLC103	Quit Claim Deed	6/1/2017	12/31/2099
957-MLC109	Quit Claim Deed	10/1/2017	12/31/2099
957-MLC111	Quit Claim Deed	6/1/2019	12/31/2099
957-MLC112	Quit Claim Deed	4/1/2020	12/31/2099
609-RML061	Warranty Deed	12/31/2013	12/31/2099
609-RML062	Warranty Deed	12/31/2013	12/31/2099
609-RML063	Warranty Deed	12/31/2013	12/31/2099
609-RML064	Warranty Deed	12/31/2013	12/31/2099
609-RML065	Warranty Deed	12/31/2013	12/31/2999
609-RML066	Warranty Deed	12/31/2013	12/31/2099
609-RML067	Warranty Deed	12/31/2013	12/31/2099
609-RML068	Warranty Deed	12/31/2013	12/31/2099
609-RML069	Warranty Deed	12/31/2013	12/31/2099
609-RML070	Warranty Deed	12/31/2013	12/31/2099
609-RML071	Warranty Deed	12/31/2013	12/31/2099
609-RML072	Warranty Deed	12/31/2013	12/31/2099
609-RML073	Warranty Deed	12/31/2013	12/31/2099
609-RML074	Warranty Deed	12/31/2013	12/31/2099
609-RML075	Warranty Deed	12/31/2013	12/31/2099
609-RML076	Warranty Deed	12/31/2013	12/31/2099
609-RML077	Warranty Deed	12/31/2013	12/31/2099
609-RML078	Warranty Deed	12/31/2013	12/31/2999
609-RML079	Warranty Deed	12/31/2013	12/31/2099
609-RML080	Warranty Deed	12/31/2013	12/31/2099
609-RML081	Warranty Deed	9/10/2013	12/31/2999
609-RML082	Warranty Deed	9/10/2013	12/31/2099
609-RML084	Warranty Deed	7/10/2015	12/31/2099
609-RML085	Warranty Deed	12/20/2013	12/31/2099
609-RML086	Warranty Deed	12/20/2013	12/31/2999
609-RML087	Warranty Deed	12/20/2013	12/31/2099
609-RML088	Warranty Deed	12/20/2013	12/31/2999
609-RML089	Warranty Deed	12/20/2013	12/31/2099
609-RML091	Warranty Deed	2/21/2014	12/31/2099
609-RML092	Warranty Deed	7/21/2014	12/31/2099
609-RML094	Warranty Deed	10/16/2014	12/31/2099
609-RML095	Warranty Deed	2/19/2015	12/31/2099
609-RML096	Quit Claim Deed	6/8/2015	12/31/2099
609-RML097	Warranty Deed	6/25/2015	12/31/2099
609-RML098	Warranty Deed	6/25/2015	12/31/2099
609-RML099	Warranty Deed	8/12/2015	12/31/2099
609-RML100	Warranty Deed	4/8/2016	12/31/2099

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine


609-RML101	Warranty Deed	4/8/2016	12/31/2099
609-RML102	Warranty Deed	5/8/2016	12/31/2099
609-RML103	Warranty Deed	9/9/2016	12/31/2099
609-RML104	Warranty Deed	2/11/2017	12/31/2099
609-RML105	Warranty Deed	5/26/2017	12/31/2099
609-RML106	Warranty Deed	6/14/2017	12/31/2099
609-RML107	Warranty Deed	6/28/2017	12/31/2099
609-RML108	Warranty Deed	7/28/2017	12/31/2099
609-RML109	Warranty Deed	8/23/2017	12/31/2099
609-RML110	Warranty Deed	8/28/2017	12/31/2099
609-RML111	Warranty Deed	10/10/2017	12/31/2099
609-RML112	Special (Limited) Warranty Deed	12/21/2017	12/31/2099
609-RML113	Warranty Deed	1/26/2018	12/31/2099
609-RML114	Warranty Deed	1/23/2018	12/31/2099
609-RML115	Warranty Deed	3/16/2018	12/31/2099
609-RML116	Warranty Deed	6/18/2020	12/31/2099
609-RML117	Warranty Deed	11/28/2018	12/31/2099
609-RML118	Warranty Deed	3/21/2019	12/31/2099
609-RML119	Warranty Deed	3/21/2019	12/31/2099
609-RML120	Warranty Deed	6/4/2019	12/31/2099
609-RML121	Warranty Deed	12/30/2019	12/31/2099
609-RML122	Warranty Deed	2/26/2020	12/31/2099
609-RML123	Warranty Deed	7/17/2020	12/31/2099
609-RML124	Warranty Deed	12/10/2020	12/31/2099
609-RML125	Warranty Deed	1/11/2021	12/31/2099
609-RML126	Warranty Deed	6/15/2021	12/31/2099
609-RML127	Warranty Deed	9/3/2021	12/31/2099
609-RML128	Warranty Deed	11/18/2021	12/31/2099
609-RML129	Warranty Deed	12/23/2021	12/31/2099

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Mississippi Lignite Mining Company – Red Hills Mine

3.4 SIGNIFICANT ENCUMBRANCES TO THE PROPERTY

The Red Hills Mine currently has no significant encumbrances to the property. No mining permit violations have been issued at the Red Hills Mine in the past ten years. One NOV was issued in April 2020 for a water quality exceedance that was determined to not be the fault of Red Hills Mine and no further action was required. Permitting requirements are discussed in Section 17.0 of this TRS.

3.5 SIGNIFICANT FACTORS AND RISKS

MLMC has not identified any significant risks that may affect the right or ability to perform work on the property. However, if a lease were to expire and MLMC had not yet noticed this property for disturbance by mining activities, the landowner may choose not to release this property for mining.

3.6 REGISTRANT ROYALTIES AND INTERESTS

Discussed in Section 3.3 of this TRS.

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4.0 ACCESSIBILITY, CLIMATE, LOCAL RESOURCES, INFRASTRUCTURE, AND PHYSIOGRAPHY

4.1 PHYSIOGRAPHY, TOPOGRAPHY AND VEGETATION

The Red Hills Mine, located in Choctaw County, Mississippi, is part of the “red hills phase” of the North Central Hills physiographic province. The region is characterized by dissected upland hills and relatively wide flats in the major stream drainages. The maximum relief of the Red Hills Mine is approximately 280 feet (msl), with the elevation ranging from 360 feet (msl) in the Big Bywy drainage in the north to nearly 640 feet (msl) in the Tertiary upland ridge tops in the southeastern area of the Red Hills Mine.

The Soil Survey of Choctaw County indicate the land-use of the county is approximately 73-percent commercial forestland. Vegetative baseline studies of the permitted areas further indicate the prominent vegetation of the Red Hills Mine to be forested pine plantations along with managed pine habitats which include prepared clearcuts and areas with young, planted pine. Other vegetative designations include deciduous forest, grassland, cropland, and residential lawns.

4.2 ACCESSIBILITY

Local access to the Red Hills Mine is by way of Highway 9 between Ackerman, Mississippi and Eupora, Mississippi which connects to Pensacola Road that leads to the Red Hills Mine paved access road. Pensacola Road connects with Highway 9 approximately 5 miles north of Ackerman, MS. The mine road is approximately 1 mile west from Highway 9 along Pensacola Road.

Travel to the Red Hills Mine by air is possible using the Jackson-Medgar Wiley Evers International Airport in Jackson, Mississippi, approximately 104 miles south of the mine, and then using ground transportation, traveling via Highway 25, Highway 15, and Highway 9. Alternatively, the Golden Triangle Regional Airport is a smaller airport approximately 50 miles from the Red Hills Mine by means of Highway 82 west, Highway 15 south, and Highway 9 north.

The Red Hills Mine is in close proximately to river ports of the Tennessee-Tombigbee Waterway and the Mississippi River. The Lowndes County Port is approximately 60 miles east of the mine. The Port of Greenville is approximately 135 miles west of the mine, and the Port of Vicksburg, approximately 150 miles southwest of the mine. All ports are connected by major state and federal highways.

In additional to transportation via roadways, air and waterways, the Kansas City Southern (KCS) railroad has a depot located approximately 5 miles south of the mine in Ackerman and is accessible by Highway 9 and Highway 15.

4.3 CLIMATE

The climate of the Red Hills Mine varies seasonally with a warm, humid summer and a generally mild, humid winter. The Red Hills Mine operates through all seasons. Heavy precipitation events may temporarily slow production but have minimal impact on the overall mining operation. Nearby Ackerman, Mississippi has the following climate (Climate in Ackerman, Mississippi, 2021):

- 56 inches of rain annually, on average

- One inch of snow per year

- 96 days per year with some sort of precipitation

- 217 sunny days per year

- Temperatures: July High: 90°F; January Low: 31°F

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Mississippi Lignite Mining Company – Red Hills Mine

4.4 LOCAL RESOURCES AND INFRASTRUCTURE

The towns of Ackerman, Eupora, Starkville, Louisville, Kosciusko, and numerous smaller communities are within a 40-mile radius of the Red Hills Mine and provide a vast employment base. Furthermore, Mississippi State University (MSU) is located approximately 30 miles east of the mine in Starkville. MLMC has a history of partnership with MSU as well as the local community colleges for science, technology, engineering, and mathematics (STEM) research and skilled trades training.

The Red Hills Mine sources power for mine office facilities and operations from 4-County Electric Power Association, and water for the mine office facilities from the Choctaw Water Association. Fuel for equipment is supplied by a local vendor. Most supplies to operate the mine are within the region. The Red Hills Mine has, or is currently constructing, all supporting infrastructure for mining operations through the LOM plan. See Section 15.0 of the TRS for further detail pertaining to the mine specific infrastructure.

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Mississippi Lignite Mining Company – Red Hills Mine

5.0 HISTORY OF THE PROPERTY

5.1 PREVIOUS OPERATIONS

There were no previous mining operations on the Red Hills Mine property.

5.2 EXPLORATION AND DEVELOPMENT HISTORY PRIOR TO MLMC

Original exploration of the Red Hills Mine area was conducted by Phillips from 1975 to 1980. Phillips contracted independent drilling services to drill and geophysically log over 800 boreholes. Phillips identified 387 million tons of lignite across 21,500 acres through the initial exploration. The data collected from the Phillips’ drilling exploration was the basis of the Red Hills Project, which included the Red Hills Mine and the RHPP.

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Mississippi Lignite Mining Company – Red Hills Mine

6.0 GEOLOGICAL SETTING, MINERALIZATION AND DEPOSIT

6.1 GEOLOGY

REGIONAL GEOLOGY

The Red Hills Mine is in the Wilcox Group of Mississippi (Figure 6.1) which is the most prolific lignite-bearing stratum in the state of Mississippi. The Wilcox Group and underlying Midway Group were deposited during Paleogene time; 66 to 23 million years ago. The most prominent characteristics of the Wilcox Group formations are the cyclical deposition and lateral persistence of the lithologic units, especially the lignite seams. The stratigraphy of the Wilcox Group is depicted on Figure 6.2. The section from the Gravel Creek Member through the Tuscahoma Formation represents a transition from a transgressive sequence of valley fill, marginal marine strata (lower Gravel Creek) to predominantly regressive, nonmarine, deltaic strata (upper Gravel Creek through the Tuscahoma).

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Figure 6.1. Geologic Formations of Mississippi (Dicken, Nicholson, Horton, Foose, & Mueller, 2005)

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The regional structural geology is fairly consistent. The regional strike is northwest-southeast. The strata are nearly flat lying, dipping to the southwest at only 25 to 35 feet per mile. No evidence of any significant faulting has been observed in the region.

LOCAL AND PROPERTY GEOLOGY

The average thickness of the Wilcox section containing the mineable lignite seams at the Red Hills Mine and surrounding area is approximately 140 feet (Figure 6.2). Vertical repetition of the geological characteristics results in a straightforward depositional setting facilitating comprehensive analysis of the geological, as well as the geochemical, geotechnical, and geohydrological baseline conditions of the Red Hills Mine.

Following the regional geology, trends in lignite seam sulfur content at the Red Hills Mine support a geologic transition from marine to nonmarine environments. Increased sulfur values are generally associated with marine influences. The C-seam marks a transition from higher sulfur below to lower sulfur contents above.

The local structural geology for the Red Hills Mine also follows the regional structure with a northwest-southeast strike dipping to the southwest. The lignite seams are gently undulating due to differential compaction of the underlying sediments. Small, localized faults have been encountered within the lignite seams while mining through the MS-002 permit area, and are anticipated to be encountered in the MS-004 permit area. These faults have been discontinuous and the seam displacement has typically been less than 10 feet. The faults have not materially affected mining or production at the Red Hills Mine.

Since mining began, no unique or especially significant geological features, formations, or paleontological resources have been identified at the Red Hills Mine. No known workings of active, inactive, or abandoned underground mines have been identified. Additionally, no fatal flaws related to geological conditions have been identified.

6.2 MINERAL DEPOSIT TYPE

The Red Hills Mine is solely focused on mining lignite from the project area. Details on the geological units encountered at the Red Hills Mine are described below and shown in Figure 6.1:

GRAVEL CREEK MEMBER

The top of the Gravel Creek Member of the Nanafalia Formation (Wilcox Group) lies just below the C-seam and includes a thin sand layer directly beneath the C-seam. The C-seam is currently the lowest lignite seam stratigraphically mined. However, upon further exploration, the B-seam may be mined in the future, particularly in areas with low laying terrain within the MS-004 permit area.

A basal sand unit, of up to 100 feet in thickness or more, characterizes the Gravel Creek Member. From the limited drill hole data that extends through this member, it appears that these sand units can be fairly widespread, but also may be completely absent. On the geophysical logs and limited cuttings data, the sand unit typically appears to be fairly massive and poorly- to well-sorted, fine- to medium-grained sand. These sand units, along with the sands in the underlying Coal Bluff Formation (Midway Group) are often referred to as the Lower Wilcox aquifer.

Above this basal sand are interbedded silt, clay, sand and lignite (A-seam). Due to the relative depth, anticipated lower quality, and closer proximity to the basal sands, the A-seam is not currently considered a resource targeted for mining.

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GRAMPION HILLS MEMBER

Five of the six lignite seams recovered at Red Hills Mine are contained in the Grampian Hills Member of the Nanafalia Formation (Wilcox Group). The formation conformably overlies the Gravel Creek Member and consists of interbedded and interlaminated clays, silts, sands, and lignite. Overall, the section is relatively sand poor.

The clays and silts are typically finely interlaminated. Munsell color varies from dark gray (N 4/ to N 5/) to greenish gray (10BG 5/1). Immediately below the lignite seams, the color is dark grayish brown (10YR 4/2) due to the presence of carbonaceous fragments. These carbonaceous layers often contain lignitized plant roots establishing an autochthonous origin for the peats that formed the lignite seams.

The sands are light gray (2.5Y 7/1) to gray (N 5/) or greenish gray (5GY 5/1). The pale greenish-gray color of many of the sands and silts is a distinctive feature of this unit. Typically, the sands are very-fine-grained, and commonly interbedded with silts and clays. One exception is the tabular sand bed between the D-seam and C-seam. The sand units between the D-seam and G-seam are typically silty, infrequent, lenticular, and probably represent narrow sand channels in the crevasse splay sequences that were penecontemporaneous with peat accumulation. Sand and silty sands compact much less than silts and clays. This phenomenon is probably the chief cause of the gentle structural undulations found in the lignite seams.

Cemented horizons, commonly referred to as “hard streaks”, are also associated with the sand units. These indurated zones are most abundant within the sand channels and the silty, sandy natural levee deposits flanking the channels. The thickness of these hard streaks ranges from less than one foot to about two feet. These zones are cemented with calcite, silica, iron oxide, or siderite, and are suggestive of periods of sub-areal oxidizing conditions during deposition. Modern analogies in the natural levee deposits of the Mississippi Delta have been noted.

The color of the lignite seams ranges from black (N 2.5/) to very dark gray (10Y 3/1). Occasional layers of carbonaceous clay or zones of clay clasts increase the ash content of the lignite. The minimum thickness for recovery is one foot. The maximum thickness of the lignite seams is about eight feet.

TUSCAHOMA FORMATION

The Tuscahoma Formation (Wilcox Group) conformably overlies the Grampian Hills Member of the Nanafalia Formation. The basal portion of this formation is the uppermost stratum to be disturbed by mining. The base of the Tuscahoma is marked by a predominantly sandy, often coarse-grained unit with a variable thickness of 10 feet to 110 feet. The variability is due to the occurrence of contemporaneously bedded clay, silt, and lignite. Laterally, these sands grade into finer grained overbank deposits including lignite seams. The overbank facies of the Tuscahoma are essentially identical to the descriptions for the Grampian Hills Member described above.

The H-seam, which is the uppermost seam that will be consistently recovered, lies at the base of the Tuscahoma. Because of its relatively high stratigraphic position, the H-seam is restricted to the upland areas above approximately 450 feet in elevation within the Red Hills Mine. Other lignite seams lying above the H-seam, including the H2-seamand the I-seam, may be encountered on occasion and are mined when seam thickness and quality are sufficient.

6.3 STRATIGRAPHIC COLUMN

A typical stratigraphic column is shown on Figure 6.2 while a planer view of two cross sections are is included on Figure 6.3a. Geologic cross section E-W2 and geologic cross section C-C’ are included as Figures 6.3b and 6.3c, respectively. The cross-sections were constructed primarily based on the drill hole geophysical logs supplemented with lithology descriptions from the drill cuttings, as well as the data from the core holes. The stratigraphic framework of the geologic cross sections follows the detailed surface mapping and subsurface investigations completed by the MDEQ, Office of Geology.

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Mississippi Lignite Mining Company – Red Hills Mine

Figure 6.2. Stratigraphic Column of the Red Hills Mine.

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Figure 6.3a. Geologic Cross Sections planer reference.

Figure 6.3b. Geologic Cross Section E-W2, MS-002 permit area (Excerpted from SMCRA permit MS-002, R3, Appendix 2509-6).

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Mississippi Lignite Mining Company – Red Hills Mine

Figure 6.3c. Geologic Cross Sections C-C’ and D-D’, MS-004 permit area (Excerpted from SMCRA permit MS-004, Appendix 2509-6).

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7.0 EXPLORATION

7.1 EXPLORATION

No exploration work other than drilling and associated geophysical logging has been conducted at the Red Hills Mine. Geophysical logging is discussed with drilling in Section 7.2 of this TRS.

7.2 DRILLING EXPLORATION

Data collected during drilling exploration programs at the Red Hills Mine is the sole information available for modeling the lignite deposit for the determination of Mineral Resources. Coal core drilling following the U.S. Geological Survey’s (USGS) guidance for sampling coal for chemical analysis is the exclusive method used by Red Hills Mine for modeling quality of the lignite deposit. The Red Hills Mine lignite deposit is evaluated on a seam by seam basis. Drilling exploration data including geologic lithologies, qualities, and hole locations have been compiled electronically in Excel files. Cross sections produced from drill hole data are shown in Section 6.3 of this TRS. The information below summarizes the various drilling programs.

DRILLING TYPE AND EXTENT

Drilling exploration programs conducted at the Red Hills Mine have comprised largely of rotary wash drilling methods. For the purpose of this TRS, senior geologist and field geologist refer to qualified representatives of MLMC and/or NACoal. Historically, MLMC has contracted independent drilling services and geophysical logging services to operate under the guidance and direction of MLMC. Drill holes completed at the Red Hills Mine are vertical in orientation and have been broken into four categories which are described below. A drill hole location map for the Red Hills Mine is presented in Figure 7.1.

Exploratory drill holes, also referred to as pilot holes, typically range in size from 4.0 to 4.5-inches outer hole diameter (od) and terminate at a minimum of 10-feet below the lowest targeted lignite seam as specified by the senior geologist. Drill hole cuttings are typically recovered by the driller, in accordance with established drilling and sampling protocols, on a 5 or 10-foot interval and are described by the field or senior geologist. All pilot holes are geophysically logged by an independent geophysical logging contractor for natural gamma, density, caliper, and resistivity responses. Related drilling data has been reviewed by the QP for inclusion in the geologic model.

Coal core holes to collect samples for quality testing are advanced next to pilot holes at specified locations in accordance with protocols described herein. Core holes are typically 6.5-inches (od) or 4.25-inches (od) with a respective sample diameter of 3.3-inches (od) or 2.125-inches (od). Samples are collected with a double core barrel or Shelby tube sampler. Coring intervals are determined by the field geologist and reviewed by the senior geologist based on the pilot hole’s geophysical log and cuttings descriptions. Core holes terminate 10-feet below the lowest targeted lignite seam. Typically, coal cores from the drilling campaigns at the Red Hills Mine are fully recovered. The minimum core recovery accepted is 90-percent (see Section 8.0 for discussion on sample preparation). Coal core data have been reviewed by the QP for inclusion in the geologic model.

Overburden core holes, or continuous cores, are drilled following protocols similar to the coal cores as described above. Rather than specifying specific intervals to collect coal cores for quality testing, overburden cores are advanced in continuous ten-foot core sections using a double core barrel or Shelby tube sampler from top of hole to bottom of hole such that the field or senior geologist can log and sample burdens in addition to lignite. Burden (overburden and interburden) samples are shipped to a separate independent soil laboratory for geochemical analysis. Overburden cores require 75-percent total run recovery for soil analysis, while coal core intervals require a minimum of 90-percent recovery within continuous core runs, such that parameters outlined for coal core collection previously are maintained. Data specific to the coal cores collected during these continuous core sampling programs have been reviewed by the QP for inclusion in the geological model.

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Mississippi Lignite Mining Company – Red Hills Mine

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Figure 7.1. Location of Drill Holes.

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GENERAL DRILLING PROCEDURES

Details may vary with each exploration program and are discussed in the next subsection, however general procedures for drilling at Red Hills Mine include:

–Identification of land control; acquire drilling leases for properties not owned or previously leased and noticed.

–Site preparation.

–Rotary wash drilling by an independent drilling contractor; typically, cuttings are collected every 5-feet until a depth of 30-feet is reached then cuttings are collected every 10-feet to final depth.

–Field geologist logs description of cuttings including depth, texture, general color.

–Independent contractor geophysically logs drill hole for natural gamma, density, caliper, and resistivity.

–Field geologist reviews geophysical log.

–Hole determined complete and abandoned by independent drilling contractor in accordance with state regulatory requirements.

–Survey drill hole collar location.

To continue with a coal core hole:

–Coring intervals are determined by field or senior geologist from pilot hole geophysical log.

–Coal core drilling by an independent drilling contractor.

–Core extracted from barrel by independent drilling contractor and placed in logging tray.

–Field geologist cleans core sample of drilling mud, measures the core length and identifies the roof and floor. If an acceptable length of core is not recovered, independent drilling contractor may attempt to retrieve the remaining core from the current hole. If no success, the core run interval will be “re-cored” as an additional core hole. After sufficient attempts have been made to re-core the interval, the field geologist may accept a core recovery of 90-percent.

–Field geologist logs the core including depths, fractures, texture, color, and characteristics of the lignite.

–Field geologist double bags and double tags sample.

–Once all intervals are cored, independent contractor geophysically logs drill hole.

–Field geologist reviews geophysical log.

–Hole determined complete and abandoned by independent drilling contractor in accordance with state regulatory requirements.

–Survey drill hole collar location.

Additional drilling tasks include:

–Maintaining daily drilling report and record of collected samples.

–Proper storage of lignite core samples in secure location of the mine office and transfer to the warehouse to prepare for shipment to laboratory.

DRILLING EXPLORATION PROGRAMS

Numerous drilling exploration programs have been conducted at the Red Hills Mine. Over 1,400 exploration holes have been drilled. 281 of those drill hole locations were sampled for coal quality testing. Table 7.1 and the text below describes the various drilling programs at Red Hills to date.

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Notes:

1 Contracted by Phillips Coal Company; included Diversified Drilling Services

2 Pilot Holes include Geotechnical Holes

3 Core Holes include Continuous Core Holes

4 Pilot Holes include Geotechnical Holes and Monitoring Wells

5 Core data excluded from model due to uncertainty in drilling method

6 Pilot Holes include Monitoring Wells

Table 7.1 Exploration Drilling Summary.

1975 - 1980

From 1975 to 1980 Phillips conducted drilling exploration activities. Independent drilling contractors including Diversified Drilling Services and Century Geophysical Logging Services (Century GLS) completed this work using rotary wash drilling methods. Initial hole spacing in 1975 and 1976 averaged three quarters of a mile. In 1979 and 1980, the general spacing of drill holes averaged 1500-feet, however spacing still exceeded a half mile in areas.

All drill holes were geophysically logged, and field logs were maintained to describe the geology. Coal cores collected during these drilling campaigns had an average linear core recovery of 99.8% and were analyzed by Core Laboratories, Inc. in Tyler, Texas. The method used to survey these drill hole locations is unknown.

These data were the basis for the characterization of the lignite deposit to justify the Red Hills Project including the Red Hills Mine and the RHPP. Despite uncertainty in how these early drill holes were surveyed, the data collected by Phillips has remained fairly consistent when compared to current fill-in drilling and quality analyzed during active mining operations. The QP has evaluated the reliability of the drilling data provided by Phillips to NACoal including review of geophysical logs, field logs, and coal quality certificates. Drill holes deemed reliable, such that at minimum lithology could be verified by a geophysical log have been used to model the lignite structure, and core holes in which the quality data could be verified by laboratory reports were used to model lignite quality. Original drilling files acquired from Phillips are securely stored in the NACoal corporate warehouse.

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1997-1998

In 1997 and 1998, MLMC conducted a drilling exploration program which primarily increased the drill hole density of the first 5-year mining block in the MS-002 permit area to an average spacing of 1000-feet or less. 12 of the 59 drill holes were distributed across the northern portion of the permit area and largely consisted of continuous cores in which soil geochemistry was evaluated in addition to lignite quality. Phillips personnel oversaw drilling activities. Drilling activities consisted of rotary wash methods and was performed by Diversified Drilling Services and Century GLS. Geophysical logs, field logs, and lab results were maintained for each hole during this program. The average coal core recovery rate from 1997 through 1998 was 100%. Coal cores were analyzed by Core Laboratories, Inc. in Tyler, Texas. Collar surveys were obtained by handheld GPS units. It is unknown to what accuracy these surveys were obtained. However, the QP feels the data is appropriate for use in the geologic model after comparison of the collar elevations with the pre-mine topography.

2000-2008

From 2000 through 2008 Diversified Drilling Services and Century GLS were contracted by MLMC to drill over 180 holes using rotary wash methods. Hole types included pilots, coal cores, and continuous cores which increased the hole density, again to an average spacing of 500-feet, within the MS-002 permit area immediately ahead of active mining. Senior and field geologists from MLMC oversaw these drilling activities and logged core samples. The average coal core recovery rate from 2000 through 2008 was 99.9%. Core samples were shipped to Standard Laboratories in Casper, Wyoming for analysis. Collar surveys were originally obtained by Trimble units connected to a known base station, followed by Leica survey equipment for a brief period until Topcon Hyper V Rovers with RTK correction tied to a known GPS base were established in 2007.

Upon the QP’s review of drilling data completed from 2000 to 2008, copies of the laboratory analysis for the 22 core holes in 2003 were not available to check the quality inputs stored in the electronic, geologic database. The QP contacted Standard Laboratories for copies of the original quality reports. However, the time of record exceeded the laboratory’s holding period of seven years and copies were not available. The QP then compared the related quality of the drilling database to the associated month end reconciliation reports and found that modeled tonnages in the area of the 2003 drilling were representative of the actual mined tonnage as shipped to the RHPP. As such, it is the QP’s opinion that the quality values documented in the electronic, geologic database for these 22 holes are representative of the deposit.

2009-2015

From 2009 through 2015, MLMC contracted Aquaterra Engineering, LLC (Aquaterra), a Terracon Company, which fully transitioned to Terracon in 2011 to perform drilling exploration work. Century GLS and Cardno Geophysical Logging Services (Cardno GLS) were contracted by MLMC to geophysically log the drill holes. Approximately 180 holes were drilled including pilots, coal cores, continuous cores, and monitoring wells. The majority of drilling was once again focused in the MS-002 permit area ahead of mining operations to achieve an average drill hole density of 1000-feet or less. However, in 2015, MLMC also began fill-in drilling within the MS-004 permit area where the next mine area was projected to be in full operation in 2023. The extent of work for the MS-004 permit area included 6 continuous core holes and 3 monitoring well locations. Senior and field geologists from MLMC oversaw these drilling activities and logged core samples which were shipped to Standard Laboratories in Casper, Wyoming for analysis. The average coal core recovery rate from 2009 through 2015 was 100%. Collar surveys were obtained by Topcon Hyper V Rovers with RTK correction tied to a known GPS base.

Most of the area drilled from 2009 through 2015 in the MS-002 permit area was mined out by December 2020.

2016

In 2016, Liberty Fuels, another subsidiary of NACoal, conducted drilling services for MLMC under a mutual cost reimbursement agreement. Cardno GLS was contracted to geophysically log the drill holes. 34 holes were drilled using rotary wash methods within the MS-002 and MS-004 permit areas. Two core holes were drilled successfully during this program targeting the F-seam and C-seam quality in the MS-004 permit area. Due to poor core recovery

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on multiple attempts, no other seams were sampled for quality during this program. Senior and field geologists from MLMC oversaw these drilling activities and logged core samples which were shipped to Standard Laboratories in Casper, Wyoming for analysis. The coal core recovery of the sampled F- and C-seams in 2016 was 100%. Collar surveys were obtained by Topcon Hyper V Rovers with RTK correction tied to a known GPS base.

2017

In 2017, MLMC contracted Great Southern Engineering (GSE) to collect lignite cores for quality assessment using sonic drilling methods, but due to uncertainty in the representative quality from excessive heating and fracturing of the coal cores during the sample collection process, the QP determined these coal core data would be excluded from the geologic model. 7 pilot holes in advance of these coal cores were conducted by Geotechnical Engineering Associates (GEA) using rotary wash methods. Century GLS geophysically logged these holes. Collar surveys were obtained by Topcon Hyper V Rovers with RTK correction tied to a known GPS base. Information related to the pilot holes in advance of these coal core holes, including geophysical logs and cuttings descriptions were evaluated by the QP and included in the geologic model to further define the structure of the lignite deposit.

2018-2021

From 2018 to 2021, MLMC contracted MHC X-Ploration Corporation, Century GLS, and Marshall Miller and Associates (previously Cardno GLS) to drill and geophysically log approximately 170 pilot holes, coal core holes, and a monitoring well. The holes were drilled using rotary wash methods, and were primarily concentrated in the MS-004 permit area to increase the drill hole density north of the planned boxcut location. However, drilling activities also included the MS-002 permit area as well as additional exploration outside the currently permitted areas. Senior and field geologists from MLMC oversaw these drilling activities and logged core samples which were shipped to Standard Laboratories in Casper, Wyoming for analysis. The average coal core recovery rate from 2018 through 2021 was 100%. Collar surveys were obtained by Topcon Hyper V Rovers with RTK correction tied to a known GPS base.

QUALIFIED PERSON OPINION – DRILLING EXPLORATION

The drilling campaigns completed from 2015 through 2021 in conjunction with the original exploration conducted by Phillips chiefly influence the Red Hills Mine Mineral Resource estimations discussed in Section 11.0. The QP served as the senior geologist who oversaw the drilling exploration programs conducted from 2015 to 2021 at the Red Hills Mine.

As described in the above drilling programs, MLMC does plan exploration activities to attain an average 500-foot drilling density for the four-year projection ahead of active mining operations. This drilling density is optimal for day-to-day operations to capture the gentle undulation of the lignite seams. Identifying these slight differences in roof elevations is key to optimizing lignite recovery efforts, particularly on the thinner seams.

However, as a whole, it should be noted for the purpose of Mineral Resource estimations and LOM projections, the QP has determined a high level of confidence in a minimum drill hole spacing of 1500-feet to 2000-feet. This confidence comes from the continuity of the lignite seams including both lithologic and quality characteristics, as well as the ability to compare modeled seam projections to active and historical mining operations. Slight structural changes are defined in the tighter drill hole spacing, but overall thickness and quality does not drastically change in a 2000-foot spacing, see Section 6.0 for cross sections. Further justification of drill hole distances specific to Mineral Resource Classifications is discussed in Section 11.0.

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7.3 HYDROGEOLOGIC CHARACTERIZATION

SURFACE WATER

Beginning in 1996, surface water monitoring sites were established and monitored by Mississippi State University (MSU) under the direction of MLMC within the various streams and tributaries surrounding and intersecting the Red Hills Mine. Baseline flow rates collected by MSU were compared to selected USGS stations within the vicinity of the study area watershed and were analyzed to characterize general runoff conditions. Surface water flow measurements were performed at the monitoring stations using the velocity-area method. As recommended by the USGS, if the depth of flow was greater than two feet, a two-point method of measuring average velocity was used.

To further characterize study area watersheds, rainfall-runoff simulations were performed for storm events with a duration of 24 hours and different return periods. These simulations were performed using the U. S. Army Corps of Engineers HEC-1 flood hydrograph model. Necessary HEC-1 model input includes watershed area, specified rainfall loss and runoff methods, and a design precipitation event. The Soil Conservation Service (SCS) method, now the Natural Resources Conservation Service (NRCS), for abstractions utilizing a curve number (CN), was chosen as the loss rate method, and a SCS/NRCS idealized unit hydrograph was used to model watershed runoff response, as study area watersheds are generally small. Modeled precipitation events were obtained from the U. S. Weather Bureau’s Technical Paper No. 40.

Based on baseline flow data, the average runoff for the Red Hills Mine was determined to be approximately 1.25 cfs/square mile of drainage area.

Surface water samples from each monitoring site were collected and analyzed for physical and chemical parameters including pH, conductivity, total dissolved solids (TDS), sulfate, chloride, total suspended solids (TSS), iron, manganese, nitrates, dissolved trace metals, coliforms, acidity, alkalinity, and various organic pollutants. All of the monitoring sites exhibited waters with very similar water quality and with very small seasonal variations. Averages of general water quality results from baseline data include a pH of 6.9 s.u., conductivity of 55 umohos/cm, TDS of 54 mg/l, and TSS of 8 mg/l. Laboratory analytical analysis for samples taken from the monitoring sites for baseline water quality was conducted by Inter-Mountain Laboratories, Inc. Surface water samples were analyzed by EPA approved methods current at the time of sample collection.

GROUNDWATER

In 1996 and 1997 MLMC contracted R.W. Harden & Associates to conduct hydrogeologic studies focusing on groundwater. Work conducted included construction of test wells, sampling of groundwater chemistry, measurement of potentiometric surfaces, and testing of the aquifers.

The primary water bearing strata at the Red Hills Mine is within the Wilcox group, which is composed primarily of fine-grained deposits of interbedded clay, sandy clay and silt. Sand thicknesses were acquired from geophysical log data gathered during the early Phillip’s exploration drilling programs and test well installation for initial characterization of aquifers within the Red Hills Mine.

Approximately 43 test wells were installed as part of the initial studies. Water levels were measured quarterly in all test wells constructed to determine potentiometric surface of various sand units. Aquifer testing, including pump tests and slug tests, was conducted in 15 of the test wells to study the more permeable horizons in the overburden and underburden of the mine. The testing indicated transmissivities ranging from 0.2 to 16,600 gallons per day per foot, and provided a range of hydraulic conductivities ranging from 0.004 to 31 feet per day. Horizons with higher hydraulic conductivity were generally associated with the coarser sand units in the underburden. Aquifer test results in overburden sands generally show lower transmissivities because only thin sand layers are present and are typically of finer and siltier texture.

Laboratory hydraulic conductivity tests were conducted on clay samples taken from boreholes drilled in the permit area. Results from eight permeability tests indicated, as is typical of Wilcox clay units, that hydraulic conductivities of these clays were low, ranging from 1 x 10-7 to 9.4 x 10-9 centimeters per second, and thus, clay units acted as

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confining layers to the stratigraphically lower Wilcox sand units. Results of these tests indicated little or no vertical hydraulic communication between sand units separated by clay strata. The layers of clay, predominant in the overburden and underburden materials, act effectively as confining layers. This was confirmed by the results of the laboratory hydraulic conductivity tests indicating low values for these clays.

Natural groundwater movement rates, in both water-table and artesian areas, are very slow and range from a few feet to 50 feet per year in the more permeable sand zones. Vertical hydraulic communication between sand zones is known to be small when separated by low hydraulic conductivity clays. This was demonstrated by the amount of rejected recharge during aquifer testing, indicating little seepage into adjoining beds downdip, and pumping-test data, indicating essentially no influence on drawdown between overlying and underlying sand zones.

Twelve months of water well, monitoring well and spring groundwater quality data was collected by MSU from 21 test wells in 1997 for alkalinity, hardness, total suspended solids (TSS), major cations/anions and select metals. Water samples collected for analyses were analyzed by an independent laboratory, ETC Laboratory, in Memphis, TN. Groundwater samples were analyzed by EPA approved methods current at the time of sample collection. Groundwater quality results from the Wilcox sands is fresh with average total dissolved solids concentrations less than 300 milligrams per liter (mg/L) and minor to moderate iron and manganese concentrations thought to be naturally occurring.

QUALIFIED PERSON OPINION – HYDROGEOLOGIC CHARACTERIZATION

The hydrogeology of the Red Hills Mine has been well studied. MLMC has continued to gain an understanding of the water bearing units during mining, established groundwater and surface water monitoring programs, fill-in drilling, and installation of new monitoring wells. In the QP’s opinion, these additional observations and collected data from the past 20 years of mining align with the results of the original surface water quantity measurements, aquifer tests, hydraulic conductivity tests, and water quality results.

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Figure 7.2. Groundwater Map.

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7.4 GEOTECHNICAL STUDIES

EARLY GEOTECHNICAL STUDIES

Geotechnical soil drilling has been carried out at the property during several investigations. The most notable studies concerning baseline geotechnical properties are described below.

In 1997, Burns Cooley Dennis, Inc. conducted a study to establish ground conditions and geotechnical properties for the various formations in the Red Hills project area. Three geotechnical boreholes to a maximum depth of 70 feet were completed using a 6-inch diameter short-flight earth auger to a depth of 10-feet followed by rotary wash methods to final depth. Each boring was sampled to a depth of 60-feet, drilled an additional 10-feet then geophysically logged by Century GLS. All soils encountered during drilling were classified with respect to material composition and consistency or density by a geotechnical/geological engineer.

Following the previous investigation in 1997, Geoscience Engineering, LLC. completed four cored holes (including an initial pilot hole) drilled to depths ranging from 170 to 360 feet at a 6-inch diameter. The pilot holes and core holes were advanced using rotary wash methods. Soil Samples were collected using a double core barrel.

In 2004, Aquaterra Engineering, LLC. completed eight soil borings using rotary wash methods to a maximum depth of 200 feet. Each soil boring was advanced with a 4-inch diameter drill bit. The soil sampling program included the collection of both disturbed and undisturbed soil samples. The samples were collected at various depths. Relatively undisturbed samples were obtained by pushing a 3-inch diameter, Shelby tube sampler to collect soil samples for geotechnical laboratory testing.

Locations of geotechnical borings are shown on Figure 7.3.

The typical geotechnical borehole log included the following geotechnical descriptions and records of the samples collected during investigation:

Lithology: Descriptions of the lithology (typically sandy silts, silts and clayey silts) are recorded for each stratigraphic interval in conjunction with a soil type in accordance with the Unified Soil Classification System (USCS). The soil types encountered by Burns Cooley Dennis, Inc., 1997 at the boring locations include clayey sands (SC), silty sands (SM), slightly silty sands (SP-SM), silty and sandy clays (CL), clays (CH) and lignite.

Consistency/Relative Density: Aquaterra Engineering, LLC., 2004 determined the relative strength estimates of the sample by hand penetrometer readings. In the more granular conditions at this site and at locations where the very dry nature of the surface soils prevented undisturbed sampling, Standard Penetration Testing (SPT) was performed.

Sample Type and Laboratory Data: The soil borings included various samples collected during the geotechnical investigations. The Aquaterra Engineering investigation (2004) collected piston (Shelby tube) samples (2.0 to 2.5 feet in length) at nominal 10-foot intervals. The piston samples are considered to be relatively “undisturbed” samples and suitable for laboratory testing such as the various strength tests. The index properties determined were the moisture content, Atterberg limits, and grain size determination. The laboratory investigation by burns Colley Dennis, Inc., 1997, included unconfined compression tests, consolidated and unconsolidated undrained triaxial compression tests, water content determination, shear strengths, mechanical sieve analysis, proctor compaction tests, and chemical/corrosion testing. The laboratory investigation by Geoscience Engineering, LLC., 1997 determined the undrained shear strength, unconfined compression test, drained shear strength, moisture content, Atterberg limits, consolidation, and grain size analysis of site materials.

The geotechnical reports available for the QP’s review did not document QA/QC protocols and procedures followed by the independent contractor at time of testing and sample collection, however the laboratory standards were indicated. The typical laboratory tests performed in the three investigations described above were performed in

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accordance with the relevant American Society for Testing and Materials (ASTM) standards at independent certified laboratories and include the following:

Soil Index properties:

Moisture content determination – ASTM D 2216, ASTM D 4959

Atterberg limit determination – ASTM D 4318

Consolidation tests – ASTM D 2435

Grain size determination – ASTM D 422 and ASTM D 1140

Soil Strength properties:

Direct shear strength tests – ASTM D 3080

Consolidated shear strength tests – ASTM D 3080

Unconfined compression tests – ASTM D 2166

Unconsolidated undrained triaxial tests – ASTM D 2850

Consolidated undrained triaxial compression tests – ASTM D 4767

In the QP’s opinion the laboratory testing methods completed to determine the geotechnical soil parameters are appropriate for the purpose of detailed pit design outlined in Section 13.5 of this TRS.

Further detail concerning pit design and ground control parameters related to geotechnical studies and additional geotechnical studies related to pore water pressures and effects on pit stability are discussed in Section 13.0 Mining Methods.

BUFFER BLOCK STUDY

In 2011, NACoal conducted an additional geotechnical study to determine the design parameters for a buffer block left between future mine area boxcuts directly adjacent to previously mined pits at the Red Hills Mine. NACoal contracted Terracon, an independent geotechnical company, to drill, sample, and conduct laboratory testing for 8 soil borings within the area of interest (Figure 7.3). Century Geophysical, an independent contractor, geophysically logged the bore holes.

The soil sampling program included the collection of both disturbed and undisturbed soil samples. Relatively undisturbed samples were obtained by pushing a three-inch diameter, Shelby tube sampler a distance of two feet into the soil in general accordance with ASTM D1587.

After the Shelby tube was removed from the boring, the sample was carefully extruded in the field and visually classified. Relative strength estimates of the sample were obtained by penetrometer readings. Disturbed portions of the sample were discarded and the undisturbed sample was placed in a protective container for transportation to the laboratory. An additional portion of the sample was placed in a plastic jar to minimize moisture loss during transport to the laboratory and to aid in visual classification of the sample.

In more granular conditions, the standard penetration test (SPT) was performed. In this case, representative disturbed samples were obtained in cohesionless soils by driving a 2-inch OD split-spoon sampler a distance of 18 inches into the soil with blows from a 140-pound hammer falling a distance of 30-inches (ASTM D 1586). Representative samples removed from the split spoon sampler and placed in plastic jars to minimize moisture loss provided a sample for laboratory testing.

At selected boring locations, auger samples were also collected to allow collection of soils for classification purposes only. In this case, the sample was retrieved directly from the auger being used to advance the boring. The auger sample was placed in a plastic jar to minimize moisture loss during transport to the laboratory.

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The soil samples were delivered to the Terracon laboratory for testing. Laboratory test assignments were made by NACoal. Laboratory testing was accomplished to determine index and strength properties of the soils encountered. These procedures are listed below.

Index properties: Moisture content (ASTM D2216), Atterberg Limits (ASTM D4318), Grain Size Determination (ASTM D422 and D1140), and Standard Effort Compaction Test (ASTM D 698)

Strength Tests: Unconfined Compression (ASTM D2166), Consolidated Undrained Triaxial Compression (ASTM D4767), Unconsolidated Undrained Triaxial Compression (ASTM D2850), Direct Shear Test (ASTM D3080)

Permeability Tests (ASTM D5084 and ASTM 2434)

All soils were visually classified and in accordance with criteria stipulated by Unified Soil Classification System (USCS).

During the soil boring advancement and sampling operation, observations for free groundwater was not made because the rotary wash technique was used for the entire boring advancement. Therefore, groundwater levels were not determined. However, ground water information from existing monitoring wells and on-site ground water management programs was available.

Using the results of the laboratory tests and field observations, NACoal conducted a slope stability analysis using the computer program Slope W and a method called Morgenstern-Price to obtain likely factors of safety for opening up a boxcut adjacent to a previously mined pit. Three scenarios for block widths between mine areas were analyzed including a 500-foot block, 250-foot block, and 100-foot block. All scenarios initially assumed 41-degree slopes on either side of the buffer block. All three scenarios resulted in a recommendation that the low wall of a new boxcut adjacent to a previously mined area should be no steeper than 30-degrees to prevent instability and increase the factor of safety near the low wall slope to 1.3.

In the QP’s opinion the drilling, sampling, testing, and analysis completed were appropriate to establish low wall pit parameters for opening up a box cut for a new mine area adjacent to a previously mined pit. In the current LOM plan, this parameter only applies to the Mine Area 2 boxcut.

QUALIFIED PERSON OPINION – GEOTECHNICAL STUDIES

Subsurface conditions and geologic units encountered have remained fairly consistent since mining commenced in 2000. Overburden core holes in which individual sections of burden were collected and tested for physical and geochemical properties, as described previously under drilling exploration, have been evenly distributed throughout the permitted mine areas and continually serve as an indicator for soils to be encountered ahead of mining. Furthermore, the geologic structural data acquired from geophysical logs during drilling campaigns indicate consistent depths between burdens and lignite seams among other subsurface characteristics. Special situations, such as deep pore water pressures described in Section 13.0 of this TRS, have led to additional geotechnical studies specific to the issue encountered while mining. However, the general pit parameters defined by the above studies have not warranted a need for further studies from the continued information obtained from drilling exploration and active mining operations. The QP understands that additional geotechnical studies may be required on an as needed basis to address special conditions that may be encountered in future mining.

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Figure 7.3. Location of Geotechnical Borings.

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8.0 SAMPLE PREPARATION, ANALYSES, AND SECURITY

8.1 SAMPLE COLLECTION AND SHIPMENT

The Red Hills Mine lignite deposit is evaluated on a seam by seam basis. As a regular practice in the coal industry, lignite cores are bagged and sent to the independent coal testing laboratory. The procedures at the Red Hills Mine for current and historical sample collection are summarized below.

Core runs are specified by the senior and/or field geologist by referencing the geophysical log of the pilot hole. As coal seams rarely exceed 6 feet in thickness, a single 10-foot core run can typically capture a full lignite seam. Once a specified core run is brought to the surface, the field geologist observes the drillers extract the lignite sample from the double barrel core to ensure the integrity of the sample is maintained, and to verify the top and the bottom of the coal core run. The core sample is transferred from the core barrel to a core cradle (i.e. halved pvc pipe) and is carried to the field geologist’s work station. The field geologist washes excess drilling mud from the core sample with water, verifies the roof and floor of the lignite core is present and checks the expected coal seam thickness referenced from the pilot hole’s geophysical log to determine coal core recovery. If full core recovery cannot be verified, the driller may attempt to retrieve the remainder of the lignite core run from the current hole. If no successful attempt is made to recover the remaining lignite, the driller must re-core the lost interval in a new adjacent core hole to achieve a minimum of 90-percent recovery.

Upon verifying recovery of the core run, the field geologist succinctly, but thoroughly logs the lignite run. A typical log describes:

–“to” and “from” depths of burdens and lignite;

–joints and fractures at specified depths;

–characteristics of burden above and below the lignite core;

–roof and floor of lignite seam (i.e. sharp or gradational);

–presence of pyrite or petrified wood;

–observations of clay or sands imbedded in the lignite core;

–and any other prominent characteristics.

After the field geologist describes the core run, the entire lignite section is double bagged and double tagged. Tags include the date, mine identifier, hole ID, seam ID, and “to” and “from” intervals. Double bagging preserves the moisture of the sample, and double tagging safeguards the identification of the sample from the field through transportation to the independent laboratory. Historically, Red Hills Mine has not photographed coal cores prior to bagging samples, but intends to incorporate photographs as a regular QA/QC practice in logging core samples beginning with the 2022 drilling campaign.

Lignite cores may be split into multiple samples for the following reasons:

–Prominent roof, floors, or partings within a continuous seam;

–Identification of composition concentrations (i.e. to determine if sulfur trends toward top, middle or bottom of seam).

Total core runs are shipped for analysis following industry standards, thus split samples in the context of a retained sample are not stored at the Red Hills Mine. Lignite tends to be a high moisture coal which oxidizes rapidly and does not have a long shelf life once removed from the ground. If core split samples were retained, they would not be representative of in-situ coal properties over time.

After samples are bagged, they are stored in a dry, shaded area, typically the field geologist’s truck, until the geologist returns to the mine office. Core samples are then securely stored in the senior geologist’s office until transferred by the geologist to specified pallet boxes in the warehouse to be shipped to the independent laboratory. The warehouse is climate controlled, such that the samples are not kept in a hot environment that could adversely

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affect the quality results. Furthermore, the Red Hills Mine office and warehouse is secured with user specified fob access and camera surveillance.

Prior to shipping the samples, the senior geologist reviews each sample against the field records and the chain-of-custody (COC). The date, mine identifier, hole ID, seam ID, and “to” and “from” intervals are verified. In addition to the COC included in the physical shipping container, a copy is emailed to the laboratory manager to notify that a shipment is in route. Copies of the COC forms for coal cores shipped from 2015 through 2021 were available for the QP to review. Coal core samples are shipped to the independent laboratory via insured freight with tracking information.

8.2 SAMPLE PREPARATION AND ANALYSIS

Minimum analyses of coal cores include short proximate (ash, calorific value (BTU/lb), sulfur, moisture) and specific gravity. These parameters are the primary quality inputs used to model the Red Hills Mine lignite deposit. Additional analyses of coal cores may include mineral analysis of ash, trace elements, ash fusion, and forms of sulfur. Historically, full proximate, ultimate analysis, and grindability have been requested on a specialized basis. However, these parameters are not modeled or currently relevant for consideration in Mineral Resource estimations.

As mentioned in Section 7.0, coal cores collected by Phillips in the early years of exploration were sent to Core Laboratories, Inc., an independent laboratory in Tyler, Texas. QA/QC information related to these samples was not provided to MLMC by Phillips when data was acquired in 2000. However, the QP was able to review laboratory certificates to verify quality data related to these core holes.

Since 2000, Red Hills Mine has sent lignite core samples to Standard Laboratories, Inc. (Standard), an independent laboratory in Casper, Wyoming for analyses. Standard is a certified ANAB Accredited and ISO 17025 accredited laboratory for coal including typical lignite coals.

The Mineral Resources QP and principal geologist for NACoal toured the Standard Laboratory facility in Casper, Wyoming on June 24, 2021. The QP reviewed procedures for chain of custody, QA/QC, and observed laboratory processes and found the operation to be clean, well-managed, and professionally operated. No concerns were noted.

Short proximate parameters, as used to define Mineral Resources and Reserves, are tested at the Casper laboratory location. Other tests at the Casper location include, but are not limited to, mineral analysis of ash and ash fusion. Lignite core samples requesting trace mineral analysis and forms of sulfur analyses are completed by the Freeburg, IL Standard laboratory location from sample splits prepared at the Casper location.

The laboratory ASTM standards used at the Casper location are listed in Table 8.1. A modification to ASTM D3302/D3302M-18 Total Moisture is completed at Standard. Due to lignite having a higher moisture content and faster oxidation rate than higher rank coals, the temperature limit for air-drying was modified to reduce the drying time. Minimal to no evidence of bias was noted in any of the parameters (TM, Dry Ash, AR BTU/lb, MAF Btu) in any of the modified drying times and temperature combinations.

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Specific Tests and/or Properties Measured	Specification, Standard, Method, or Test Technique	Items, Materials or Product Tested	Key Equipment or Technology
Ash in the Analysis Sample	ASTM D 3174	Coal	Furnace
Calorific Value	ASTM D5865	Coal	Calorimeter
Carbon, Hydrogen, and Nitrogen	ASTM D5373	Coal	Elemental Analyzer
Equilibrium Moisture	ASTM D1412	Coal	Waterbath Method
Free-Swelling Index	ASTM D720	Coal	Electric Method
Fusibility of Ash	ASTM D1857	Coal	Furnace
Grindability of Coal	ASTM D409/D409M (MOD)	Coal	Grindability Machine
Loss on Ignition	ASTM 7348	Coal	Oven/Furnace
Major and Minor Elements	ASTM D6349	Coal	ICP-OES, Mixed Acid Digestion
Mercury	ASTM D6722	Coal	Direct Combustion Analysis
Moisture in the Analysis Sample	ASTM D3173	Coal	Oven
Moisture (Total)	ASTM D3302/D3302M (MOD)	Coal	Commercial Method
Preparing Samples for Analysis	ASTM D2013/D3302M (MOD)	Coal	Crusher/Pulverizer
Sulfur (Total)	ASTM D4239	Coal	Furnace
Volatile Matter	ASTM D7582	Coal	TGA
Water Soluble Alkali Content	ASTM D8010 Method A	Coal	ICP-OES

Table 8.1. List of ASTM standards for Standard Laboratory, Casper location.

Receiving Dock/Sample Storage Room

The receiving dock doubles as the sample storage room and is climate controlled (ventilated and heat). Casper, WY has a moderate summer climate, with cold winters that can be mitigated with heaters. From the receiving dock and storage room there is access to the sample prep room and main laboratory.

During non-operational hours Standard is locked down with an active alarm system including door, window and motion detectors which is monitored by a local company.

Once a shipment is received, the shipment is logged and opened then the number of individual samples are logged along with the date and time. Each sample is cross referenced with the COC and is then weighed using certified

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balances. Paper records including Standard laboratory logs, COC’s, and any additional paperwork received in the shipment are transferred to an electronic database at this point.

Once samples are logged, they are stored in this storage room until there is available space in the prep room. It was noted there is a slight potential for moisture loss during this storage period. MLMC acknowledges this potential and, as such, double bags samples in the field to preserve as much in-situ moisture as possible.

Retained pulverized and dried 60-mesh samples are also stored in this room. These samples can be retested within 6 months for selective parameters. Due to the sample being dry and potential for oxidation moisture parameters and Btu/lb cannot be retested. Standard contacts and verifies with the client prior to disposal of retains.

Prep Room

The prep room is a temperature-controlled room (AC and Heat) accessible from the receiving dock. Within the prep room samples are crushed to 8-mesh size using a Holmes crusher and are then run through a Holmes riffler. Pulverizer screens and rifflers are inspected daily, before and after each batch. The distance between the riffler fin spread is regularly checked in accordance with ASTM standards. An air hose is used to clean out after each sample to mitigate contamination. It was noted that the prep room was very clean. No visible residual material was observed in the riffler.

8-mesh samples are divided into 1000 g per tray following ASTM standards using calibrated balances. Additional sample material is placed in a bag which then has the air mechanically removed and heat sealed for storage in a separate room off of the prep room. The same storage process is used for round robin samples. Similar to the retained samples, Standard verifies with the client prior to disposal of sample splits.

Prepared 1000 g trays are placed in one of three air dry units for overnight drying following the modified standards discussed previously. Drying time and temperatures are regulated on the air-dry units. Certified thermometers are used which also indicate minimum and maximum temperature values to ensure there is no exceedance of the max allowable temperature. Temperature gauges are certified annually, and additional checks are performed quarterly.

Once air-drying is complete and samples are re-weighed and logged. Dried samples are pulverized to 60-mesh and split samples are obtained with a Holmes sample riffle. Split samples are stored in pre-labeled high-density polyethylene (HDPE) bottles with foam lined caps.

Laboratory Testing

After the prep room process, 60-mesh split bottles are transferred to the main portion of the laboratory where they are first run through a mixing wheel for 10 minutes to ensure a homogeneous sample. All equipment maintains logs of processes and results. This portion of the laboratory is climate controlled (AC and heat).

Review of all analysis results is by the laboratory manager, or assistant laboratory manager. Review includes but is not limited to identification of outliers, and comparison of results with historical information by site, if available. The laboratory manager may request a rerun on a sample if needed.

8.3 QUALITY CONTROL PROCEDURES

There is currently no formal program in place at Red Hills Mine for the inclusion of blanks, standards, pulverized duplicates, or field duplicates. However, Standard completes several internal QA/QC checks to verify samples.

Standard also participates in a monthly round robin coal testing program including 32 other laboratories. A 4-mesh program and an 8-mesh program are included in this round robin. In 2020, Standard also participated in a lignite (coal) specific round robin testing program facilitated by NACoal including 8 commercial laboratories that were used by various NACoal mine locations. The round robin consisted of four samples labeled 2001, 2002, 2003, and 2004. Two samples were sourced from Red Hills Mine and two samples were sourced from another NACoal mine. The two locations provided a range of samples with variability in moisture, ash, sulfur and sodium. The labs

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participating in the round robin were provided 8-mesh splits and dried 60-mesh splits of all 4 samples. The general results are summarized in Figure 8.1. Standard is labeled “Laboratory #6” and all results fell within ASTM Range.

Figure 8.1. NACoal 2020 Round Robin Program Summary. (NACoal, 2020)

In addition to the monthly round robin coal program, a formal Proficiency Testing Program by Quality Assurance Resources, LLC (QAR PTP) which includes a 4-mesh program and 8-mesh program is also completed monthly. If there is an error or out of tolerance reported, an investigation is immediately completed. Upon investigation, corrective action will be taken to remediate the issue and additional training will be completed if deemed necessary. Trainings were documented. The most current QAR PTP results were posted and personally reviewed by the QP and NACoal’s principal geologist during the lab visit.

Along with the above programs, internally at Standard, a daily short proximate testing program was in place.

8.4 QP STATEMENT ON THE ADEQUACY OF SAMPLE PREPARATION, SECURITY AND ANALYTICAL PROCEDURES

Although no formal written procedure existed until recently for the process to collect coal samples at the Red Hills Mine, the consistency in core collection from one drilling program to the next has been thoroughly documented. Through records review and personal observation of numerous drilling campaigns, it is the QP’s opinion that historic coal core collection has remained consistent with U.S. Geological Survey’s (USGS) guidance for sampling coal for chemical analysis. The process of double bagging and tagging the cores in addition to multiple checkpoints to log samples from field to shipment to the laboratory further ensures the integrity and security of each sample is maintained.

Additionally, in the QP’s opinion the methodologies used by Standard Laboratories are within ASTM standards for sample preparation, process of sample splitting and reduction, general quality control, and security of samples to ensure that validity and integrity of samples is upheld.

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9.0 DATA VERIFICATION

9.1 DATA VERIFICATION PROCEDURES FOR MINERAL RESOURCES

VERIFICATION OF DRILLHOLE DATA AND GEOLOGIC (MINERAL RESOURCE) MODEL

The drilling database for the Red Hills Mine was organized into three Excel files related to lithology intervals, collar survey, and quality. The files encompassed the geologic modeling inputs including lithology picks, total depth of hole, base of oxidation (weathering), hole coordinates, and coal core quality data. A secondary compilation of drilling data was created to verify completeness of data related to each drill hole including the file location of geologist field logs and laboratory certificates or reports for core quality, and details of each drilling program such as contractors who performed the work and year drilled.

The drilling files were saved on the MLMC network drive which contains the geologic model and has limited access by engineering and geology at MLMC.

Once the drilling database was compiled, a series of routine data integrity checks were performed by the QP on the database to check for common errors and omissions. The QP visually inspected the database after updates were made, then conducted a second data validation check using Maptek Vulcan software. The validation checks included, but were not limited to, the following:

- Verified each hole has a unique collar location.

- Verified the total hole depth on the collar table matches the total depth on the lithology table.

- Verified the from and to depths on the lithology table and quality table increase down hole.

- Verified for overlapping intervals in the lithology table based on from and to depths.

- Verified the from and to depths on the quality table match the associated seam depths on the lithology table.

For any errors or omissions reported, the QP reviewed the geophysical logs, field logs, and quality reports related to the specified holes to reconcile the differences.

After the initial checks were performed, the QP identified any holes in close proximity to other holes such as twinned or re-drilled holes. If two drill holes fell within 50-foot of one another, the data from the two holes was reviewed. The hole with the highest confidence and most complete data was selected to be included in the model. After database checks and reconciliations were completed, the QP completed the modeling process which is detailed in Section 11.1 of this TRS.

The QP who serves as the senior geologist at MLMC in conjunction with the corporate principal geologist for NACoal individually reviewed and validated the constructed geological model using various checks between drill hole data and modeled horizons. Drill hole locations were randomly selected to verify modeled values of each horizon and were found to be representative of the imported drill hole data. Additional visual inspection of the model included review of various consecutive cross sections as well as isopach maps of the modeled structure and quality. Newly modeled grids were also compared to previous models. Changes in modeled values were minor and isolated to areas where new drilling data had been included from recent exploration programs. Anomalies were reviewed against the original drill hole data, any errors in the drilling database were reconciled and the model was reconstructed.

It is the QP’s opinion that the analytical results from the coal cores collected during MLMC’s exploration programs are consistent with actual as-delivered quality from the active mining operations at the Red Hills Mine. This opinion was based on comparison of historical quality projected from the geologic model for the annual operating plans to actual as-delivered quality indicated by the customer’s (Red Hills Power Plant) independent laboratory, Advanced Analytical Laboratories. It is also the QP’s opinion that the modeled structure of the lignite seams is consistent with active mining operations based on comparisons of modeled seam thickness and trends against actual surveyed seam thicknesses and trends.

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The QP found the geologic model for Mineral Resource estimation was a reasonable and reliable representation of the geologic structure and quality of the lignite seams (horizons) at the Red Hills Mine.

VERIFICATION OF THE REASONABLE PROSPECT FOR ECONOMIC EXTRACTION TO SUPPORT MINERAL RESOURCE ESTIMATION

The Red Hills Mine has acquired data related to mine development and production within the local lignite deposit over an extended operational history. The QP verified the assumptions made for the estimation of Mineral Resources were well within accuracy required for an initial assessment (IA) level of study based on actual historical metrics and a contract period defined by the LSA with the RHPP. Data referenced for verification included actual month end reconciliations, production reports, and mine permit requirements. The potential for economic extraction is justified by the terms of the existing LSA with the RHPP through April 2032.

9.2 LIMITATIONS ON DATA VERIFICATION FOR MINERAL RESOURCES

Representatives of MLMC or NACoal were not involved in the original drilling exploration programs conducted by Phillips prior to 1997. MLMC obtained the collar surveys, geophysical logs, coal core analyses, and geologist field logs for each hole from Phillips, but was unable to observe the drilling, sampling, or sample preparation related to these data. The largest uncertainty lies in the method of the collar survey of the early data drilled from 1975 to 1980. It is unknown to what degree these holes were surveyed. Collar elevations for these early drill holes were plotted against a topographic digital terrain model (DTM) contoured at 5-foot intervals and checked for discrepancies. All plotted drill hole locations fell appropriately within the respective contour interval.

MLMC, historically, has contracted Diversified Drilling Services and Century GLS, contractors used by Phillips for the early exploration, to perform in-fill drilling programs, such that MLMC has gained familiarity in these contractors’ drilling and downhole mapping methods. Furthermore, comparisons of new drilling data to the older Phillips data have been completed as fill-in drilling progresses ahead of mining. These comparisons, and the level of documentation Phillips provided upon acquisition of the coal assets translates to a level of confidence in these data to use in the geologic modeling for Mineral Resource estimation. Nonetheless, there is still some uncertainty related to the Phillips drill hole data which the QP has considered in the determination Mineral Resource estimations as discussed in Section 11.0 of this TRS.

Additionally, as discussed previously in Section 7.2 of this TRS, the QP was also unable to verify laboratory records for the 22 coal cores collected in 2003 as included in the drilling database. The QP reached out to the independent laboratory for copies of the original quality reports. However, the time of record exceeded the laboratory’s holding period of seven years and copies were not available. The QP then compared the related quality of the drilling database to the associated month end reconciliation reports and found that modeled tonnages in the area of the 2003 drilling were representative of the actual mined tonnage as shipped to the RHPP. After this comparison, the QP determined the uncertainty in the modeled 2003 quality would not materially affect the Mineral Resource estimations.

9.3 QP’S STATEMENT OF ADEQUACY OF DATA FOR MINERAL RESOURCES

Data disclosed in this TRS used for the preparation of geologic models for the purpose of Mineral Resource estimations at the Red Hills Mine have been verified by the QP. The QP has been involved with the collection of these data during drilling exploration programs since 2011 and has had direct oversight of the drilling campaigns at the Red Hills Mine since 2015. These data include drill hole surveys, geophysical logs, coal core quality, and other relevant test data. Procedures discussed previously in this section were used by the QP to reconcile any discrepancies upon review of the available data. In addition to a substantial geologic database, historical data since the mine opened the original boxcut in 2000 was available to the QP to review to ensure appropriate mining costs were applied to estimate Mineral Resources.

It is the QP’s opinion that the data provided for this TRS is sufficient for the determination of Mineral Resources at the Red Hills Mine.

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine

9.4 DATA VERIFICATION PROCEDURES FOR MINERAL RESERVES

VERIFICATION OF HYDROGEOLOGY DATA

Groundwater and surface water studies were conducted on the Red Hills Mine site, as described in Section 7.3 of this TRS, and used to develop mine plans as described in Section 13.0 of this TRS. The QP has reviewed the findings of these studies and believe they are thorough, complete and provided the necessary information for the start-up and ongoing operation of the Red Hills Mine. Sampling and modelling techniques used in the studies were adequate and completed in a professional manner for a PFS level assessment of the hydrology/hydrogeology. The locations of the surface water sampling sites and monitoring/test well locations are adequate for the MS-002 and MS-004 areas. The Red Hills Mine has operated for 20 years and is continuously gaining an improved understanding of how the groundwater and surface water impacts mining operations along with environmental compliance.

VERIFICATION OF GEOTECHNICAL DATA

Several geotechnical studies were initially conducted on the Red Hills Mine site as described in Section 7.4 of this TRS and subsequent studies conducted and described in Section 13.5 of this TRS. These studies have been reviewed by the QP and they provided the basis for the mine plan designs. Sampling and modelling techniques used in the studies were adequate and completed in a professional manner for a PFS level assessment of the geotechnical parameters. It is the opinion of the QP that the geotechnical studies reviewed have been consistent with responses from the active mining operation and are adequate for use in the MS-002 and MS-004 mining areas.

VERIFICATION OF CUT-OFF GRADE DILUTION ASSUMPTIONS AND MODIFYING FACTORS

The QP reviewed the cut-off grade, dilution assumptions, and all modifying factors for completeness and reasonableness and found them to be consistent with the realized results from the active mining operation.

Quality reject specifications from the LSA are the basis for development of the cut-off grades. The QP has reviewed the cut-off grades and LSA and in his opinion these have been properly established.

Dilution parameters are reasonable and have been verified by comparing projected to actual as-delivered quality data which confirms the established dilution parameters are a good representation of final results. Recovery rates have been refined over the course of operating the Red Hills Mine and are constantly being compared to actual recoveries for verification.

Modifying factors used in pit designs, as described in Section 13.0 of this TRS, have remained consistent since mine inception with limited changes. The modifying factors have been reviewed by the QP and consistently applied in the mine design process.

It is the opinion of the QP that the cut-off grade, dilution assumptions and modifying factors are adequate for purposes of determining Mineral Reserves.

VERIFICATION OF ULTIMATE PIT CONFIGURATION

The ultimate pit configuration is defined by physical constraints including permitted boundaries and related offsets and buffers, areas where the stripping ratio exceeds economic limits, and/or the limitations of the LOM sequence. It is the opinion of the QP that the ultimate pit configuration has been properly defined and is adequate for purposes of determining Mineral Reserves.

VERIFICATION OF COST ESTIMATE, PRICING ASSUMPTIONS, AND ECONOMIC ANALYSIS

The QP has reviewed annual historical values for all costs, pricing assumptions and economic analysis to be reasonable for future projections, which are continuously refined annually as more data is collected from ongoing operations, to improve accuracy of the projections. These have been used to support parameters used during mine planning.

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Mississippi Lignite Mining Company – Red Hills Mine

WORKFORCE, STAFFING AND EQUIPMENT

The QP considers that reconciliations of staffing and workforce requirements, actual equipment capacities and productivities have been appropriately considered while establishing reliable projections of executing the mine plan. The Red Hills Mine is an active, on-going operation and the staffing, workforce, and equipment requirements are well established.

ENVIRONMENTAL FACTORS

The QP has worked closely with the Red Hills Mine Environmental Manager and has reviewed the site closure and reclamation plans and the related costs. Proper monitor programs to meet mine permit requirements are in place. Field work has been observed routinely by nature of the QP’s on-site role to verify the conditions and assumptions that underscore the environmental data used in this TRS.

9.5 LIMITATIONS ON DATA VERIFICATION FOR MINERAL RESERVES

It is the opinion of the QP that there are no limitations to data verification for Mineral Reserves.

9.6 QP’S STATEMENT OF ADEQUACY OF DATA FOR MINERAL RESERVES

The QP has verified the data disclosed, including prior technical studies used in the development of the modifying factors, cut-off grade, ultimate pit configuration, mine design, schedule, workforce and staff requirements, equipment needs, environmental factors, cost assumptions and pricing assumptions and economic analysis. The QP has been involved with the collection and use of this data since 2017 while serving as the Engineering Manager at the Red Hills Mine. Red Hills Mine has established internal policies and controls to manage the environmental, regulatory and social or community aspects for the mining operations. These are periodically reviewed by the QP and other managers at the Red Hills Mine and NACoal management for their effectiveness in a culture which follows the principle of continuous improvement. The QP is of the opinion that a reasonable level of verification has been completed and that no material issues have been left unidentified in the course of collecting and analyzing the data described in this report.

It is the QP’s opinion that the data provided for this TRS is sufficient for the determination of Mineral Reserves at the Red Hills Mine.

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine

10.0 MINERAL PROCESSING

It was identified early on that the Red Hills Mine and power plant project would only be viable if the fuel source could be used as a direct feed ROM fuel source. Therefore, no washability tests for processing or metallurgical tests were conducted.

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Mississippi Lignite Mining Company – Red Hills Mine

11.0 MINERAL RESOURCE ESTIMATES

11.1 KEY ASSUMPTIONS, PARAMETERS AND METHODS

The QP developed the stratigraphic geologic model for Mineral Resource estimation using Maptek Vulcan software. All verified drilling data as of December 31, 2021 was considered for inclusion in the model. Key assumptions, parameters and methods to estimate Mineral Resources are discussed herein.

HORIZONS

The structure of the Red Hills Mine deposit is determined by “to” and “from” depth picks from geophysical logs and geologist’s drill hole field logs correlated to the drill hole collar survey. Depth picks represent the roof or floor of a lignite seam which define each horizon or domain.

Roofs, floors and parting samples that meet a minable quality (see Table 11.1) are identified as part of the associated seam and are modeled in the same manner as the split samples described previously. Roofs, floors and partings that do not meet a minable quality are included in the geologic database as a point of record, but are not modeled with a seam identifier, and thus the quality and thickness of those sample splits are not composited with the associated seam.


Parameter	Minimum	Maximum
Calorific Value, Btu/lb	4,400	8,000
Moisture, %wt	20.0	49.4
Ash, %wt	5.0	23.5
Sulfur, %wt1	0.2	1.2

Notes: 1 Sulfur values of LSA rounded to one decimal.

Table 11.1. Quality Limits (as-received basis).

Table 11.2 presents the stratigraphic horizons modeled. Horizons considered for Mineral Resource estimates are indicated with an asterisk. Modeled horizons were required to have a minimum of ten coal core samples in the drilling database to be considered. The QP found a minimum of 10 coal core samples provided the statistical confidence to characterize the quality of a lignite seam.

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Mississippi Lignite Mining Company – Red Hills Mine

HORIZON ID

SEAM NAME

AVERAGE THICKNESS

COJ

J-Seam

1.7

CI2

I2-Seam

1.1

COI*

I-Seam*

1.6

CI1

I1-Seam

1.1

CH2*

H2-Seam*

1.4

COH*

H-Seam*

2.5

CH1

H1-Seam

1.2

CG2*

G2-Seam*

1.4

COG*

G-Seam*

3.0

CG1

G1-Seam

1.2

CG3

G3-Seam

1.3

CF2

F2-Seam

1.0

COF*

F-Seam*

2.8

CF1

F1-Seam

1.4

CE2

E2-Seam

0.9

COE*

E-Seam*

3.5

CD6

D6-Seam

1.1

CD4*

D4-Seam*

1.3

CD2*

D2-Seam*

1.2

COD*

D-Seam*

3.3

CC2

C2-Seam

0.9

COC*

C-Seam*

3.1

CC1

C1-Seam

1.0

CB2

B2-Seam

1.1

COB*

B-Seam*

3.1*

CB1

B1-Seam

1.5

CB3

B3-Seam

1.0

* Indicates horizon with an average drill hole quality and an adequate number of core samples which meet the limits for consideration as a Mineral Resource.

Table 11.2. Stratigraphic Horizons

QUALITY PARAMETERS AND DENSITY DETERMINATION

The quality parameters modeled for determination of Mineral Resources are outlined in the LSA and include calorific value (Btu/lb), moisture (wt%), ash (wt%), and sulfur (wt%); typical Short Proximate analysis reported on an as-received (AR) basis. Four quality grids of the above parameters are modeled for each horizon. The minimum and maximum quality constraints which determine feasibility to be categorized as a Mineral Resource are also defined in the LSA and are listed in Table 11.1.

In addition to the quality grids, each lignite seam (horizon) has a modeled density grid. Specific Gravity (SG) analysis is regularly tested on lignite core samples. Modeled SG values by horizon are converted to a density grid in the modeling process by converting grams per cubic centimeter (g/cc3) to tons per cubic foot (tons/ft3) such that: SG * Density of Water (62.43 lb/ft3) * 2000 lb/ton.

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Mississippi Lignite Mining Company – Red Hills Mine

MODELING PROCESS

After the QP verified the drilling data following procedures outlined in Section 9.1 of this TRS, the stored drill hole data encompassing geologic lithology picks, quality data, and collar surveys was imported into the modeling software.

Once the drilling data was imported, a preliminary topographic surface was created by triangulation of an electronic contour map of the pre-mining topography of the Red Hills Mine and surrounding area. A 50 by 50-foot grid surface was then applied to the triangulated surface. Surveyed drill holes were modeled using inverse distance with a grid cell of 50-feet to create a second topographic grid. Differences in the surface produced by the surveyed drill holes are added to the preliminary topographic surface to create the designed topographic surface of the area to be modeled.

The lithology and location tables were then referenced by the modeling program and the structural model was developed. The lignite horizons were correlated and modeled using 50-foot grid cells. During the modelling process, lithologic data were extrapolated from ten surrounding drill holes using an inverse distance squared calculation to infill the grids where appropriate.

The base of oxidation (BOX) depth determined from drill cuttings and continuous (overburden) cores was modeled to provide the limit for suitable plant growth material (SPGM) for operations. This limit also generalizes the base of weathering in that lignite above this depth has been partially oxidized and typically exhibits unacceptable quality characteristics. The depth of the BOX layer was modeled by the grid calculation method using 50-foot grid cells and the extrapolated depth of the BOX from drill hole to drill hole. Lignite seams were then subcropped based on the BOX and lignite seams above the BOX were removed from the model.

The structural model was validated based on geological cross sections and isopach maps of the seam roofs and floors that were created, and checked by the QP. Any errors identified in the lithologic descriptions were reconciled.

Lignite quality was then modeled for the entire deposit. As described above, quality data was first composited for each lignite seam by drill hole. As with the structural model, the quality model uses 50-foot grid cells to model quality of the deposit. Drill holes missing quality data employed an inverse distance squared calculation to assign averaged values from ten surrounding drill holes.

In-situ tonnages for the lignite seams were calculated within Maptek Vulcan by applying a formula to each horizon by the area, thickness, density, and real/extrapolated quality values (i.e. modeled parameters).

JUSTIFICATION OF MODELING METHODS

Historically, geologic models at the Red Hills Mine have been generated using inverse distance methods. The models have proved to be consistent with field conditions (structure and quality), which is likely attributed to the simplistic, stratigraphic geology of the region as described in Section 6.0 of this TRS. Geologic units are laterally consistent with generally graded quality. Use of inverse distance methods has proven to be robust in continuous stratigraphic deposits. The QP did not see a need for MLMC to alter geologic modeling methods.

LIMITS AND CONSTRAINTS ON THE MINERAL RESOURCE ESTIMATES

The Mineral Resources presented in Table 11.4 were estimated by applying a series of geologic and physical limits in addition to mining and economic constraints which meet the level of accuracy required for an initial assessment (IA). The potential of economic extraction is justified by the terms of the existing LSA contract and are clearly defined through April 2032. Key constraints used by the QP to determine Mineral Resource estimates are summarized below. Details pertaining to physical constraints are discussed further within Sections 3.0 and 17.0 of this TRS. Mining and economic constraints specific to Mineral Resource estimates are discussed herein.

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Mississippi Lignite Mining Company – Red Hills Mine

Geologic Constraints:

–Modeled roof and floors of each lignite seam (horizon);

–Base of oxidation (BOX).

Physical Constraints:

–Topography surface;

–Lease and fee coal boundaries;

–Surveys of mined out tonnages;

–Offsets from unleased land tracts and occupied dwellings;

–Buffers from state and federal parks;

–Existing roads and highways, major utilities, and major surface infrastructure without prior agreements for relocation or temporary closure;

–Stream offsets for Waters of the US (WOTUS) that fall outside of mitigation permits.

Mining and Economic Constraints:

–Resource categorization parameters based on distance from point of observation and drill hole sample count criteria;

–Resource pit shells developed from general mine design parameters and reasonable unit costs used to determine the max cumulative strip ratio for the tonnage to be economical;

–Stated in-situ without any mining loss, dilution or other modifying factors applied;

–Stated exclusive of Mineral Reserves;

–Limits on quality parameters presented in Table 11.1. Quality limits are specified by the LSA.

GENERATION OF PIT SHELLS FOR MINERAL RESOURCE ESTIMATES

Resource pit shells were projected and confirmed to meet the supply requirements of the LSA.

The QP determined the maximum reasonable cumulative stripping ratio was 18:1 for the Red Hills Mine deposit assuming a lignite sales price based on the LSA of $30 per ton as of December 31, 2021. The sales price has historically remained fairly steady due to the single customer contract. Assumptions of mining costs were based on knowledge of surface mining methods in a simple multi-seam, stratigraphic deposit.

Three pit shells were identified for Mineral Resource estimates. Mine Area 1 and Mine Area 2 fall within the MS-002 permit area, and Mine Area 3 falls in the MS-004 permit area.

The geologic model was used to create a stripping ratio map of the deposit. Recovery of tonnage was assumed to be 100-percent. No dilution factors were applied. The C- seam was assumed by the QP to be the lowest potentially mined lignite seam for Mine Area 1 and Mine Area 2. The B-Seam was assumed by the QP to be the lowest potentially mined lignite seam for Mine Area 3 due to the shallower depth of the seam resulting from valley terrain and the structural dip of the lignite seams. Highwalls and endwalls were projected up from the lowest mineable seam to the topography at 40-degrees, an angle appropriate for surface mining in soft materials. Preliminary pit shells were determined by the QP based on the maximum cumulative stripping ratio, then modified for any physical constraints.

MINERAL RESOURCE CLASSIFICATION AND UNCERTAINTY

Table 11.2 identified the lignite seams for initial consideration of a Mineral Resource by the QP. The indicated seams had a minimum of ten coal core samples for quality estimation, and an average coal core sample quality

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Mississippi Lignite Mining Company – Red Hills Mine

which fell within the limits provided in Table 11.1. Mineral Resources were then further defined by the three identified resource pit shells.

As discussed in Section 7.2 all drill holes within the Red Hills Mine deposit obtained structural data related to the lignite seams, where a portion of these drill holes also included quality data from the collection of coal core samples. As such, the QP determined it would be appropriate that the defined distances for Mineral Resource categories were supported by the average distance between core holes. The distribution of the average distance between core holes is presented below in Figure 11.1. Accounting for the average distance between core holes would ensure an appropriate density of the quality data was included in each Mineral Resource category. Additionally, due to the methodology of the fill-in drilling at the Red Hills Mine, a greater density of quality data would naturally encompass a greater density of structural data.

Figure 11.1. Distribution of distance between quality drill holes.

From the summary statistics of the average distance between core holes, the lower quartile was 1,106 feet and the upper quartile was 3,404 feet.

Following the quartiles of the distribution as a baseline, the QP modeled various distances from core hole collar locations, and noted a correlating confidence level at the distances of 1,000 feet, 3,000 feet, and 5,000 feet. Confidence by the QP was determined from the density of quality and structural data available within each distance combined with the associated timeframe drilling data was collected. The data collected during drilling programs in which the QP oversaw held a greater weight than data collected in earlier years. Data collected by Phillips prior to MLMC held the least amount of confidence. The QP then conducted a comparison of the modeled values at various distances to actual historical data of mined out areas and noted minimal variance of less than 5-percent between modeled tons and actual mined tons at a distance less than 1,000 feet. At a distance greater than 1,000 feet and less than 3,000 feet some variance in modeled and actual values was noted, but was minimal such that comparisons of calorific values (BTU/lb) were still within 5-percent of actuals. No historic data was available for a comparison of modeled and actual values at a distance greater than 3,000 feet.

After review, the QP determined distances from core holes of 1,000 feet, 3,000 feet, and 5,000 feet were appropriate for categorization of Mineral Resources as Measured, Indicated, or Inferred (Table 11.3).

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Mississippi Lignite Mining Company – Red Hills Mine


Mineral Resource Category	Lower Distance (Ft)	Upper Distance (Ft)
Measured	0	1,000
Indicated	1,001	3,000
Inferred	3,001	5,000

Table 11.3. Mineral Resource Categories – distances from core hole.

As stated previously, all Mineral Resource categories meet the minimum of 10 samples for estimation, meet the quality limits, and fall within a defined resource pit shell. The distinguishing factor between Measured, Indicated, and Inferred Resources is the distance of the resource from a core hole as described below and shown in Figure 11.3.

Measured Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the distance from a core hole is less than or equal to 1,000 feet. An extensive amount of fill-in drilling has occurred in areas where core holes have been drilled at a distance within 1,000-feet of each other. At this distance, much of the structural data has been tightened to a density of 500-feet or less. Most of this drilling data was collected by MLMC using known sampling methods and surveying methods. Due to the level of control and oversight during collection of this drilling data, the resulting resource estimates have a high level of confidence by the QP and a low level of uncertainty.

Indicated Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the distance from a core hole is greater than 1,000 feet and less than or equal to 3,000 feet. While a portion of this data still relies on some of the early exploration data collected by Phillips, much of the area has been filled-in with data collected by MLMC using known sampling methods and surveying methods. While some uncertainty still exists in this data due to the influence of the early Phillips drilling, a moderate level of confidence in this data has been applied by the QP from more recent fill-in drilling.

Inferred Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the distance from a core hole is greater the 3,000 feet. Modeled values at this distance require a large amount of interpolation from drilling data collected in the early exploration stage conducted by Phillip’s from 1975 through 1980 and, as such, holds the greatest uncertainty in sample collection and survey methods. Fill-in drilling, including twinned holes would increase the confidence in these data.

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Mississippi Lignite Mining Company – Red Hills Mine

Figure 11.3. Red Hills Mine Mineral Resource Classifications; distance from core hole.

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine

11.2 MINERAL RESOURCE ESTIMATES

BASIS FOR MINERAL RESOURCE ESTIMATE

The basis of the Mineral Resource estimates for the Red Hills Mine deposit and the methods in which they were prepared are summarized for this item. The S-K 1300 regulations (17 CFR 229.1300) define a Mineral Resource as:

The QP based the Mineral Resource estimates presented in Table 11.4 for the Red Hills Mine on a stratigraphic geologic model generated from the verified drilling exploration data presented in Section 7.2 of this TRS. The choice of stratigraphic modeling is due to the lateral persistence and continuous extent of the lignite seams.

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Mississippi Lignite Mining Company – Red Hills Mine

MINERAL RESOURCE STATEMENT

The categorized Mineral Resources reported herein are exclusive of in situ Mineral Reserves. The effective date of Mineral Resource estimates is December 31, 2021.

Table 11.4. Mineral Resource Estimates.

11.3 CUT-OFF QUALITY, ASSUMED COST AND SALES PRICE

Quality limits were previously discussed with Table 11.1 and in subsection Limits and Constraints on the Mineral Resource Estimates under Section 11.1 of this TRS.

11.4 QP’S CLASSIFICATION OF MINERAL RESOURCES

The criteria used by the QP to classify Mineral Resources into inferred, indicated, and measured Mineral Resources was previously discussed in subsection Mineral Resource Classification and Uncertainty under Section 11.1 of this TRS.

11.5 UNCERTAINTY IN THE MINERAL RESOURCE ESTIMATES

Uncertainty in the Mineral Resource estimates was previously discussed in in subsection Mineral Resource Classification and Uncertainty under Section 11.1 of this TRS.

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Mississippi Lignite Mining Company – Red Hills Mine

11.6 QP’S OPINION ON POTENTIAL INFLUENCES AFFECTING MINERAL RESOURCE ESTIMATES

Due to the contract provisions of the LSA, factors including contract term or likelihood of economic extraction, lignite sales price, and quality parameters/limits have far less risk of being affected than a mineral sold on the open market. Nonetheless some risks still need to be addressed.

Additional exploration may positively or negatively affect Mineral Resource estimates. Furthermore, Mineral Resource estimates may be materially affected by a change in the assumptions including general mining costs and land control. New regulations may impose additional economic factors, delays to future permit renewals, or restrictions to physical estimation boundaries.

The QP is not aware of any specific factors that would currently materially affect the prospect of economic extraction.

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Mississippi Lignite Mining Company – Red Hills Mine

12.0 MINERAL RESERVE ESTIMATES

12.1 KEY ASSUMPTIONS, PARAMETERS, AND METHODS

To develop the estimate of Mineral Reserves, modifying factors were applied to Measured and Indicated Resources. Inferred Mineral Resources were not considered for Mineral Reserves. The following modifying factors were applied using key assumptions, parameters and methods to convert Mineral Resources to Proven and Probable Mineral Reserves.

STRIPPING RATIO AND PIT LIMITS

The maximum stripping ratio for Mineral Reserves was determined from analysis of historical and future costs compared to the estimated base sales price per MMBtu as defined in the LSA through April 2032 as described in Section 19.0 of this TRS. The cost and price per MMBtu establish the maximum allowable stripping ratio limit of 14:1, which MLMC has found to provide the necessary economic mining cost compared to selling price. The maximum stripping ratio remains the same each year of the LOM plan. The base price for the dedicated lignite is defined in the LSA with the estimated average price per ton of $28.04 for lignite delivered and sold over the LOM plan. All costs were escalated at various rates based on the forward-looking Consumer/Producer Price Index with budgeted 2021 costs used as the base year. The maximum allowable cumulative stripping ratio establishes the pit limits within the Mineral Resource pit shells.

Stripping ratios remain relatively consistent across the MS-002 and MS-004 permit areas with the exception of high stripping ratios along the east side of MS-004 which defines the eastern boundary of mining.

Measured and Indicated Resources failing to meet the above criteria were not included in the Mineral Reserve estimates.

LIGNITE QUALITY

Lignite quality that failed to meet the minimum quality specifications as outlined in the LSA were eliminated from consideration and not included in the Mineral Reserve estimates.

MODELED MINING PARAMETERS

The geologic model used for estimation of Mineral Resources was modified to account for the minimum mining thickness of 1-foot and dilution parameters as described in Section 13.2 and Table 13.2 of this TRS. Additionally, seams with a parting thickness of less than 6-inches were composited.

ASSUMPTIONS AND MODIFYING FACTORS

The following key assumptions, parameters and modifying factors were used by the QP to estimate the recoverable Proven and Probable Reserves contained within the LOM:

–All recoverable lignite required to fulfill the contractual obligations of the LSA are contained within the LOM plan pit extents;

–Geological structure and quality model are as described in Section 11.0 of this TRS;

–Only Measured and Indicated Resources were included;

–Maximum stripping ratio 14:1;

–Mining production rates on a cubic yard and per ton basis remain relatively consistent with historical performance;

–Mining costs on a unit basis remain relatively consistent with historical performance;

–Depth of weathering (base of oxidation) as defined by Section 11.0 of this TRS;

–Minimum minable lignite thickness: 1.0 feet;

–Minimum parting thickness before seams are composited: 6.0 inches;

–Maximum depth of mining: approximately 320 feet;

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Mississippi Lignite Mining Company – Red Hills Mine

–The Mineral Reserves fall within the Mineral Resource pit shells which have clearly defined physical constraints;

–Mining dilution parameters defined in Table 13.2 R-O-M Dilution Parameters;

–Lignite density defined by seam from coal core drilling data and modified by dilution parameters and approximately 80 lb/ft³;

–Recovery rates by seam as presented in Table 13.3;

–Quality limits as defined by the LSA and presented in Table 11.1 were applied after dilution has been accounted for, and;

–Forecasted annual power plant MMBtu requirements.

METHOD

The RHPP provides a forecast of MMBtu requirements to MLMC on an annual basis. MLMC compares this forecast to historical plant requirements to develop a workplan of MMBtu demand for the LOM. The LOM plan assumes the RHPP will not continue to operate after the expiration of the current contract with CGLP in April 2032.

To develop the LOM plan, modifying factors including minimum mining thickness, minimum parting thickness, and mining dilution parameters were applied to the geologic (Mineral Resource) model within Maptek Vulcan to create the Mineral Reserve model.

MLMC engineers then project mining pits within Maptek Vulcan. Projections were directed to the topography from the lowest mineable lignite seam. The mining pit width is 170’ based on the current mining equipment operating parameters. The mining pit length varies based on mining pit limits. Highwalls are projected at 42-degrees. Endwalls are projected at 40-degrees with the allowance for a 150-foot wide bench to establish haul roads. Final pit extents were limited by a maximum cumulative stripping ratio of 14:1. Each pit was then sectioned into 500-foot long blocks; adjusting endwall blocks as necessary. Further justification of pit design parameters is provided in Section 13.0 of this TRS.

Once mining pits were projected, volumes, tonnages, and associated quality parameters were exported by projected block and horizon from Maptek Vulcan. The blocks were exported as volume for burden horizons and as tons for lignite horizons. The QP reviewed the exported quality for each lignite horizon block to ensure quality thresholds were met. Any lignite block that did not meet the minimum quality parameters was not considered a Mineral Reserve and the associated block was considered waste material (burden block). The exported data was then brought into a mine sequencing program designed by NACoal and MLMC engineers which is a combination of MS Excel and SQL programming. The first step in the sequencing program was to apply recovery rates to lignite tonnages by seam.

Once the above modifying factors were applied, the sequencing program allotted lignite tonnages and burden volumes to the four major operational fleets of truck and shovel, dozer push, dragline, and lignite load and haul by period based on the workplan MMBtu requirements. The sequencer creates an output of volumes by fleet, including rehandle volumes, and projected tonnages and qualities by period.

This output then flowed through a series of steps to distribute tonnages and volumes to individual equipment to determine equipment hours based on equipment production rates. Calculations also included adjustments for:

–Equipment mechanical, operational, and weather availabilities;

–Fleet capacity including limiting production factors;

–Variations in haulage routes;

–Assumptions for crew sizes and;

–New and/or retiring equipment.

The output of allotted volumes, lignite tonnages, quality, and equipment hours by period were the inputs for the Red Hills Mine financial model. These inputs flow through the financial model, which was developed and refined by MLMC based on actual performance, along with escalated inputs for cost estimates for labor, materials and supplies,

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Mississippi Lignite Mining Company – Red Hills Mine

fuel and other cost components to generate cost projections for the LOM plan. In addition to general operating costs, contemporaneous reclamation, royalties, mine closure, and capital projects were projected and escalated accordingly. It is the opinion of the QP that the final LOM plan and related projected MMBtu costs and forecasted pricing justify the selection of the maximum stripping ratio and supports the conversion of Measured and Indicated Mineral Resources to Mineral Reserves.

12.2 MINERAL RESERVE ESTIMATES

BASIS FOR MINERAL RESERVE ESTIMATE

This Item discloses the Mineral Reserve estimates for the Red Hills Mine based on the QP’s detailed evaluation of the modifying factors as applied to indicated or measured mineral resources, which demonstrate economic viability of the Red Hills Mine property. The estimated Mineral Reserves are in accordance with the definitions of “Mineral Reserve” as described by the S-K 1300 regulations (17 CRF 229.1300) as:

The reference point at which Mineral Reserves are defined, is the point of sale to the RHPP, which is after two 20k ton storage silos following the truck dump hopper.

This disclosure of Mineral Reserves is based upon the qualified person’s opinion that the LOM plan has been completed to a PFS level of accuracy, as defined in 17 CFR Part 229.1300, which includes and supports the qualified person’s determination of Mineral Reserves.

The LOM plan included annual stripping and lignite production qualities and quantities. Annual production costs were estimated based on the mine plan quantities, surface mining methods, equipment fleets in use, and unit prices that have been proven by historical production at the Red Hills Mine. The current mining methods, used at the Red Hills Mine since inception, are planned to continue until enough lignite reserve is depleted to fulfill the contractual obligations of the LSA for fuel supply to the RHPP.

12.3 CUT-OFF QUALITY AND SALES PRICE

Cut-off quality and price were previously discussed in Section 12.1 under subsection Stripping Ratio and Pit Limits.

12.4 MINERAL RESERVE STATEMENT

Based on the LOM plan and modifying factors discussed above, the Red Hills Mine contains the economically minable Mineral Reserves listed in Table 12.1. The Mineral Reserves include approximately 26.6 Mt of R-O-M lignite, with an average calorific value of 5,070 Btu/lb, moisture content of 43.4%wt., ash content of 15.0%wt., and sulfur content of 0.6%wt. The point of reference for Mineral Reserves is as delivered to the dump and RHPP silos as of December 31, 2021.

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Table 12.1. Mineral Reserve Estimates.

12.5 MULTIPLE COMMODITY MINERAL RESERVE

The Red Hills Mine is a single commodity Mineral Reserve.

12.6 QP’s OPINION ON RISK FACTORS THAT COULD AFFECT MINERAL RESERVE ESTIMATES

The Red Hills Mine began commercial deliveries in 2002. Since this is a well-established operation, the deposit, mining, and environmental aspects of the Project are very well understood. The knowledge for the Red Hills Mine is based on the collective experience of personnel from MLMC’s site operations and technical disciplines gained since mine inception. This knowledge is supported by years of production data and observations at the Red Hills Mine.

The LOM plan included annual stripping and lignite production qualities and quantities. Production costs were estimated based on the mine plan quantities, surface mining methods, equipment fleets in use, and unit prices that have been proven by historical production at the Red Hills Mine. The current mining methods, used at the Red Hills Mine since inception, are planned to continue until enough lignite reserve is depleted to fulfill the contractual obligations of the LSA for fuel supply to the RHPP.

With this said, there are some risks that could materially affect Mineral Reserve estimates. Risks include changes in customer demand for any reason, including, but not limited to, dispatch of power generated by other energy sources ahead of coal, fluctuations in demand due to unanticipated weather conditions, regulations or comparable policies which may promote planned and unplanned outages at the RHPP, economic conditions, including an economic slowdown and a corresponding decline in the use of electricity, governmental regulations and/or inflationary adjustments which could have a material adverse effect on MLMC's financial condition, results of operations and cash flows.

Other risks include unforeseen changes in the LOM plan from additional exploration, changes in land control and new regulations that could delay future permit renewals or restrictions to physical mining boundaries.

At the time of this TRS, the QP is not aware of any specific factors that would currently materially affect the prospect of economic extraction.

Uncertainty in the Mineral Resource estimates was previously discussed in in subsection Mineral Resource Classification and Uncertainty under Section 11.1 of this TRS.

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Mississippi Lignite Mining Company – Red Hills Mine

13.0 MINING METHODS

The Red Hills Mine began commercial deliveries in 2002. Since this is an established operation, the deposit, mining, and environmental aspects of the project are very well understood. The geological knowledge is based on the collective experience of personnel from MLMC operations, geology, engineering, environmental, and other disciplines gained during years of lignite mining at Red Hills Mine and other mining operations in the United States.

The lignite at Red Hills Mine surface mining operation is recovered using dragline and conventional truck and shovel mining methods due to the proximity of the lignite to the surface and the physical characteristics of the deposit. Mining operations progress in a five-step process, which includes clear and grub, overburden and interburden removal, lignite production, spoil backfill and grading, and reclamation. In the development phase, drainage and water control were established, and then the required infrastructure consisting of power, mine office and maintenance facilities, lignite stockpile facilities, and roadways were established.

The Red Hills Mine began operations in the MS-002 permit area in Mine Area 1 (MA1) and is in the process of transitioning to the MS-004 permit area to Mine Area 3 (MA3). The initial boxcut construction for MA3 began in 2021 and mining in this area will continue through April 2032. Figure 13.1 presents the layout of the Red Hills Mine and identifies the total area to be affected over the mine.

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Mississippi Lignite Mining Company – Red Hills Mine

Figure 13.1. Layout of the Red Hills Mine (larger map included as Supplemental Figure Attachment).

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Mississippi Lignite Mining Company – Red Hills Mine

13.1 GEOTECHNICAL AND HYDROLOGICAL CONSIDERATIONS

PIT DESIGN

The initial geotechnical parameters for the design of the pit slopes was provided in the Geoscience Engineering report completed in 1997 and Aquaterra report completed in 1994 to define soil index properties and soil strength parameters as discussed previously in Section 7.4 of this TRS. The early geotechnical studies were the basis of the pit design which is fully detailed in the Red Hills Mine Ground Control Plan and summarized herein.

To determine highwall stability, a circular arc failure approach has been utilized. A minimum FoS of 1.2 was calculated using the Modified Bishop Method for each highwall configuration that will be encountered by the mine. Due to the depth and multiple seam nature of the lignite deposit, benching will be required to allow for continuous burden removal and lignite mining. For individual slopes less than 80 feet, the highwall angle is stable up to 70 degrees. Between 80 and 180 feet, the effective slope angle decreases with a linear relationship from 60 to 40 degrees as shown in Table 13.1.


Depth (ft)			Effective Highwall Angle
80 to 110			60 degrees
110 to 145			50 degrees
145 to 180			40 degrees

Table 13.1. Effective highwall angle by depth.

For slopes greater than 180 feet, benching is required. Figure 13.2 illustrates the combination of highwall slopes and safety benches that are used to meet the effective slopes outlined above. In general, the truck and shovel operating level is located 150 to 160 feet above the pit floor and naturally creates bench with a minimum width of 150 feet. When benches and offsets are accounted for pits may range from 100 to 210 feet in width. Initial design assumes a 170-foot pit width.

Figure 13.2. Typical Pit Configuration for plan at steady state. (Mississippi Lignite Mining Company, 2019)

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Mississippi Lignite Mining Company – Red Hills Mine

Low wall or spoil side angles were based on the type of materials found throughout the mine area, an angle-of-repose of 33 degrees was recommended by geotechnical studies. MLMC’s digging plan reduces the effective spoil angle to 33 degrees or less by allowing for an operating bench on the spoil side of the pit.

As a whole, Red Hills Mine pits are designed with an effective highwall angle of approximately 42 degrees, effective endwall angles of approximately 40 degrees, and effective low wall angles of 33 degrees or less.

Mining has been ongoing at the Red Hills Mine since 1998 and the design methodology for the pit slopes has been satisfactory as evidenced by each pit progression. Due to the stratigraphic nature of the Red Hill Mine geology, which is checked by regular drilling exploration programs ahead of mining, repetition of geologic units leads to consistency in applying geotechnical parameters.

NACoal and MLMC engineering have made minor adjustment to the pit design since 1998. However, these adjustments are primarily for optimization, to address new equipment specifications or additional ramps to reduce haul distances. Other adjustments include additional benching in the highwall where topography is higher or the depth to the C-seam increases to establish ramps and functional road systems. This additional benching also increases the FoS of the highwall by reducing the overall effective angle in these instances. Optimization of drainage is another factor that greatly influences the pit design.

SPOIL STABILITY STUDIES

The bulk of geotechnical studies at the Red Hills Mine since 2004 pertain to spoil stability which influence operation plans for production and reclamation. Two types of spoil failures have been observed at the mine. The first type comprised of a rotational failure occurring at the toe of the dragline bench with radial cracks extending into the bench toward the spoil piles. The second bench failure type observed at the mine included heaving of the C-seam followed by a slump failure. There were several spoil studies performed using software packages developed by GEO-SLOPE International, and RocScience. Some of the pit slope analyses can be found in the report, titled “Design Report for Red Hills Mine Slope Stability Study” by Barr Engineering (Barr), 2014; “Red Hills Slope Stability Mitigation Test Plan” by Aquaterra, 2010; and “Red Hills Mine Slide Investigation” by Aquaterra, 2009.

The report, “Design Report for Red Hills Mine Slope Stability Study,” by Barr analyzed seepage conditions and slope stability of the levee setback and US Army Corps of Engineers (USACE) defined conditions with software created by GEO-SLOPE International Ltd. The integrated software suite is called GeoStudio 2012, which includes SEEP/W and SLOPE/W. SEEP/W is a finite element program that analyzes groundwater seepage within porous materials like rock and soil for traditional steady-state flow or transient analyses. The computed pore-water pressures and corresponding phreatic surface can then be imported into SLOPE/W for analysis. SLOPE/W uses limit equilibrium methods to perform slope stability analyses. An example of a slope stability analysis done by Barr is presented in Figure 13.3.

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Mississippi Lignite Mining Company – Red Hills Mine

Figure 13.3. Soil Stability Assessment. (Barr Engineering, 2014)

The report “Red Hills Slope Stability Mitigation Test Plan” by Aquaterra tried to determine changes in stresses and pore pressures during the mining operation. A 2-D coupled stress-pore pressure model was conducted using the Sigma/W application as developed by GEO-SLOPE International. The Sigma/W program provides a finite element mesh analysis stresses and deformations within the subsurface soils sing transient loads. An example of a slope stability analysis is presented in Figure 13.4.

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Mississippi Lignite Mining Company – Red Hills Mine

Figure 13.4. Slope Stability Study (Aquaterra Engineering, LLC., 2010)

To help remediate the potential rotational bench failures, the truck-shovel operation does not dump material within the first two spoil peaks from the active pit, and spoil piles are not to exceed 90-feet in height above the dragline bench height. Furthermore, extra attention is given to ensure water is not stored in spoil valleys for a prolonged period. In addition, the work area is inspected by shift supervisors and fleet leadmen for cracking, heaving, flowing groundwater, or any other abnormal conditions prior to starting work in an area, and following any precipitation or freeze/thaw event. The inspection requirements are specified as part of MLMC’s safeguards under the Ground Control Plan. A certified person must document inspections of the work areas during each shift and after every rain, freeze, or thaw. Dragline operators and groundmen are continuously monitoring bench and spoil conditions as they dig.

Potential heaving of the C-seam followed by a slump failure was attributed to the ground water recharge and increased pore pressures due to seepage from three sand seams below the C-seam. These failures are described in depth in the Barr and Aquaterra reports. Based on these studies, earthquake drains, and dewatering well systems were implemented to address the increased head pressure from the lower aquifers. These systems were installed by registered drillers immediately following the severance of the C-seam. More details on these systems were provided in the “Red Hills Slope Stability Mitigation Test Plan” report. MLMC engineers continued to install earthquake drains for a few pits once the B-seam came back into existence. Once the earthquake drains were retired, MLMC then continued to monitor the pore pressures below the dragline bench as mining progressed with wireline piezometers for a few pits and noted no pressure changes. Although earthquake drains are not anticipated for the remainder of mining in the MS-002 permit area, they are anticipated for some future areas in the MS-004 permit

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Mississippi Lignite Mining Company – Red Hills Mine

area. This assumption is based on cross referencing sand thickness maps with the B-seam existence limits and projected pits. Pore pressures below bench grade will be monitored leading into this area of interest with the installation of wireline piezometers, followed by the installation of earthquake drains with the mining progression if deemed necessary by MLMC engineers.

A dewatering well system was installed annually ahead of mining from 2008 through 2014. As discussed in the hydrogeology portion of Section 7.3 of this TRS, the upper stratigraphic sands of the Wilcox sediments which are mined through are minor. The systems MLMC put into place were a recommendation from a geotechnical study with the idea that the groundwater flow, although minimal, was contributing to the saturation of the spoils contributing to spoil side failures. With this system in place, production saw a minor improvement in drier pit conditions, but costs to implement the system could not be justified and the program was discontinued.

EXCESS SPOIL PILES

In addition to pit design and spoil stability, regulations governing the permanent placement of excess spoil require geotechnical studies to ensure stability of the placed material. In 1999, Pritchard Engineering, Inc. carried out the geotechnical investigation to gather soil index properties and soil strength properties which were then used as inputs by NACoal to perform a stability study under static and seismic conditions for the excess spoil piles in the MS-002 permit area. MLMC is in the process of constructing the first lifts of the first excess spoil pile in for the MS-004 permit area. As mining operations continue in the MS-004 permit area, a geotechnical study of similar parameters will be conducted in 2022 by an independent service to assess the stability of the spoil piles in the MS-004 permit area. Due to the similarity of the pre-mine topography for the new excess spoil piles, similar soil characteristics/chemistry, the lateral extensiveness of the geology in the region, and furthermore an extended history of operating heavy equipment in various dump conditions, MLMC does not anticipate major changes to the mine plan from future geotechnical investigations of the excess spoil piles. Existing and proposed excess spoil pile locations are shown on Figure 13.1.

13.2 LIGNITE PRODUCTION RATE, MINE LIFE, MINING DIMENSIONS AND DILUTION AND RECOVERY FACTORS

PRODUCTION RATE

The Red Hills Mine was designed to supply approximately 2.6 to 3.2 million tons of lignite per year to the adjacent RHPP. Actual production is dictated by customer MMBtu demand.

MINE LIFE

MLMC provides the lignite for the RHPP under a contract that runs through April 2032.

MINING DIMENSIONS

Mining dimensions are discussed in Sections 13.1 and 13.3 of this TRS.

HAULROAD DESIGN

Haul roads and spoil ramps are typically designed to a width of 90 to 100 feet to allow for two-way traffic. In some circumstances, temporary one-way roads may be established with proper signage. Highwall ramps are designed to a width of 70 feet, and dragline walkways must be a minimum of 120 feet wide.

MINING DILUTION

R-O-M tonnages at the Red Hills Mine meet the following conditions:

–Minimum mining thickness: 1.0 ft;

–Maximum burden depth: approximately 320 feet;

–Average lignite density: approximately 80 lb/ft3

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The base of weathering, which closely aligns with the depth of the BOX as described in Section 11.0 of this TRS may affect lignite recovery. Special considerations for lignite above this depth must be considered as it may have been partially oxidized and typically exhibits unacceptable quality characteristics for the power plant.

Mining dilution was initially determined from statistical analysis of coal core data collected from 1975 through 1997. During the 2011 drilling exploration program, roof and floor samples were collected and analyzed for each coal seam to verify dilution parameters used in modeling. The drilling data was compared to actual as-delivered quality data and confirmed that the original dilution parameters remained applicable. Dilution parameters are applied to all lignite seams and are listed in Table 13.2.


Structural (Roof and Floor)
	Loss (ft)	0.25
	Gain (ft)	0.083

Quality (Roof and Floor)
	Density (lb/ft3)	85.4
	Calorific Value (Btu/lb)	1859
	Moisture (%wt)	26.48
	Ash (%wt)	53.98
	Sulfur (%wt)	0.26

Table 13.2. R-O-M Dilution Parameters.

RECOVERY FACTORS

Recovery rates of individual coal seams are presented in Table 13.3 and were determined from various comparisons between surveyed severed tons, haul truck payloads, delivered tons to RHPP, and modeled tons accounting for dilution and minimum mining thickness. The low recovery of C-seam is due to a 50-foot wide swath of lignite that is left in the pit to assist with stabilizing the spoil and dragline bench.


Seam			Recovery Rate
H			72%
G			84 %
F			97 %
E			90 %
D			100 %
C			67 %

Table 13.3. Recovery Rates by Seam.

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Mississippi Lignite Mining Company – Red Hills Mine

13.3 REQUIREMENTS FOR STRIPPING AND BACKFILLING

The Red Hills Mine is a multiple lignite seam surface mining operation.

The primary burden removal units for a typical mining sequence at the Red Hills Mine include:

–one 82-cubic yard electric-powered walking dragline;

–one 41-cubic yard electric rope shovel;

–a fleet of 150-ton and 200-ton end-dump haul trucks and;

–four large track-type push dozers.

Lignite is severed and loaded by a surface miner or hydraulic backhoe.

Figures 13.5 through 13.7 illustrate typical pit layouts to show the mining process. Similar mining processes will be followed in both MA1 and MA3 for production and reclamation. Figures are not to scale.

First, the truck and shovel fleet remove overburden to an elevation which approximates the first minable lignite seam; usually this will be the H-seam. This overburden material is hauled to fill in the topography to final grade during the reclamation process. Truck and shovel operations may be required to remove other interburdens and rehandle material depending on sequencing/production and reclamation planning.

Following removal of the H-seam, the dozers push the interburden, which overlies the second G-seam, into the previously mined pit. This process is repeated through successive lignite seams until the accumulated interburden has reached a point where it is level across the pit. This typically occurs at or near the E-seam elevation.

Finally, the dragline sits spoil side on a bench primarily constructed from the material the dozers pushed and then removes both the D-seam and C-seam interburdens.

Figure 13.5. Pit Layout - Truck and shovel operation. (Mississippi Lignite Mining Company, 2019)

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Mississippi Lignite Mining Company – Red Hills Mine

Figure 13.6. Pit Layout – Dozer operation. (Mississippi Lignite Mining Company, 2019)

Figure 13.7. Pit Layout – Dragline operation. (Mississippi Lignite Mining Company, 2019)

Rough backfilling and grading of reclamation are accomplished using dozers as the haul trucks dump material between the dragline spoils. Hydraulic backhoes may be used to rehandle spoil material that exceeds final grade. In accordance with the mine permit requirements, a minimum of 4 feet of suitable plant growth material (SPGM), or red oxidized soil that meets textural parameters, must be placed on top of the gray unoxidized material in the dump

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unless otherwise approved. MLMC follows an approved final grading plan using a “balanced acreage” approach in that the same reclaimed areas must be brought up to grade within 29-months of lignite removal. This plan is approved for both permitted areas.

In MA1, mining progresses through three to four pits per year. Due to a shorter pit length in MA3, MLMC anticipates mining five to seven pits per year.

13.4 MAJOR EQUIPMENT AND PERSONNEL

A list of major and auxiliary equipment used at the Red Hills Mine is presented in Table 13.4. The equipment at the Red Hills Mine is well maintained, in good physical condition and is either updated or replaced periodically with newer models to maintain reliability and to keep up with technological advancements.

As equipment wears out, MLMC evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.


Unit(s)	Equipment	Approximate Production Rates	Major Fleet
1	Marion 8200 Dragline	3200 yd3 per hour	Dragline
1	P&H 2800 Electric Rope Shovel	2100 yd3 per hour	Truck and Shovel (T-S)
1	Wirtgen 4200 Surface-miner	2000 tons per hour	Lignite
1	CAT 6040 Hydraulic Backhoe	1800 yd3 per hour	T-S/Lignite Support
1	CAT 6040 Hydraulic Shovel	1800 yd3 per hour	T-S Support
1	CAT 5230 Hydraulic Shovel	1400 yd3 per hour	Lignite
1	Komatsu PC2000 Hydraulic Backhoe	1200 yd3 per hour	T-S/Lignite Support
4	CAT D-11 Tractors	850 yd3 per hour	Dozer Push
5	CAT D-10 Tractors		Dragline/Dump Support
1	CAT D-8 LGP Tractor		Auxiliary Support
3	CAT D-6 LGP Tractor		Ash Placement
1	CAT 844 Rubber Tire Tractor		T-S Support
12	CAT 789 A, B, C, & D End-Dump Trucks	200-ton payload	T-S and Lignite Haul
4	CAT 785 A & B End-Dump Trucks	150-ton payload	T-S and Lignite Haul
3	CAT 773 Side-Dump Ash Train	140-ton payload	Ash Placement
2	CAT 24 Class Motor Grader		Road/Reclamation Grading
2	CAT 16 Class Motor Grader		Road/Reclamation Grading
1	21,000 Gallon CAT 777 Water Truck		Dust Suppression
1	32,000 Gallon CAT 785 Water Truck		Dust Suppression
3	3-5 yd3 CAT Backhoes		Auxiliary Support
4	40 Tons CAT ADT trucks	40-ton payload	Auxiliary Support

Table 13.4. Major and primary auxiliary equipment list.

At normal operating levels, the Red Hills Mine on average employs +/-200 personnel (Table 13.5).


STAFF		WORKFORCE
Full Time	39	Production	97
Interns/Co-ops	1 or 2	Maintenance	56
		Warehouse	5
		Temporary	Varies

Table 13.5. MLMC Personnel.

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Mississippi Lignite Mining Company – Red Hills Mine

14.0 PROCESSING AND RECOVERY METHODS

The overall average quality of the mined lignite seams meets the quality specifications stated in the LSA without beneficiation. No mineral processing is performed by MLMC.

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Mississippi Lignite Mining Company – Red Hills Mine

15.0 INFRASTRUCTURE

The Red Hills Mine public utility lines and facilities locations are presented in Figures 13.1 and 15.1, showing the mine infrastructure and details of the mine facilities.

MLMC purchases power from 4-County Electric Power Association, a cooperative of the TVA. A 69kV line runs parallel to the TVA 500kV line from the Highway 9 Right-of-Way (R-O-W) to the mine office substation. This line then continues past the office to feed the RP-27-1 transformer and the Pump Building transformer. This line also terminates at a dragline substation pad that is currently not in use.

A second 69kV line runs north along the west R-O-W of Highway 9 to feed the dragline substation currently in use. This dragline substation will be used for the remainder of the MS-002 permit area, and the entire MS-004 permit area. MLMC anticipates a permit to bore under Highway 9 to feed dragline cable to the east side of the highway in 2022.

Water for the mine office facilities is supplied by the Choctaw Water Association via a 6-inch line which runs along the R-O-W of McIntire Road. A registered groundwater well sourced from the Lower Wilcox aquifer feeds the equipment wash bay, boot wash, irrigation, and fire hydrants.

The Red Hills Mine has a sanitary waste treatment plant with a permitted NPDES outfall. This is an active sludge treatment plant. Onsite sedimentation ponds are permitted for Beneficial Water Use and serve as the water source for dust suppression

There are no leach pads or tailings ponds at the Red Hills Mine. Lignite is mined and transported to a stockpile or to the customer’s hopper. Public roads are not used for the transport of lignite to the RHPP. Mine site haul routes are depicted in Figure 13.1 and Figure 15.1. To transport lignite from the MS-004 permit area to Stockpile B or the customer’s hopper, an overpass for Highway 9 traffic has been constructed northeast of the Hopper. Mine traffic generally travels below the Highway 9 traffic via an underpass.  A secondary haul route will be available via the dragline deadhead road (currently under construction). This is an at-grade crossing approximately 1,300 feet southeast of the overpass/underpass. The highway department must be notified in advance to detour traffic around this at-grade crossing; therefore, this crossing will only be used to mobilize large equipment or emergency use.

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Mississippi Lignite Mining Company – Red Hills Mine

Figure 15.1. Red Hills Mine Facilities Map.

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Mississippi Lignite Mining Company – Red Hills Mine

16.0 MARKET STUDIES

16.1 MARKETS

The primary market for the Red Hills Mine lignite is the adjacent RHPP for which the mine was developed. The Red Hills Mine is a mine-mouth operation where the lignite is delivered directly to the power plant. The Red Hills Mine is a high moisture, low calorific value fuel, which precludes transporting the lignite as a viable option to expand market share, thus no known marketing studies have been conducted for the Red Hills Mine. The LOM plan assumes the RHPP will not continue to operate after the expiration of the current LSA with CGLP and the expiration of the existing PPA between TVA and CGLP in April 2032. The Red Hills Mine is expected to begin final reclamation in April 2032. NACoal and MLMC have made efforts to identify specialty niche markets for the lignite with limited success.

16.2 MATERIAL CONTRACTS

Red Hills Mine is a fully developed and functioning mining operation. All aspects of the mining, haulage and delivery of lignite to the RHPP are defined in the LSA between CGLP and MLMC. The RHPP supplies electricity to the TVA under a long-term PPA. CGLP leases the RHPP from a Southern Company subsidiary pursuant to a leveraged lease arrangement. The LOM plan assumes the RHPP will not continue to operate after the expiration of the current LSA with CGLP and the expiration of the existing PPA between TVA and CGLP in 2032.

Red Hills Mine is an active operation and all material contracts are in place for the continued operation of the mine. The Red Hills Mine is a mine-mouth project where the lignite is delivered directly to the power plant using off highway haul trucks.

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Mississippi Lignite Mining Company – Red Hills Mine

17.0 ENVIRONMENTAL STUDIES, PERMITTING, AND PLANS, NEGOTIATIONS, OR AGREEMENTS WITH LOCAL INDIVIDUALS OR GROUPS

17.1 ENVIRONMENTAL AND BASELINE STUDIES

In July, 1998, a final Environmental Impact Statement (EIS) was issued for the Red Hills Power Project. The impacts of the Red Hills Mine were considered during this process. This EIS evaluated anticipated impacts associated with mining at the Red Hills Mine. The EIS evaluated project impacts to the following resources:

–Air Resources

–Geology

–Soils

–Groundwater Resources

–Surface Water Resources

–Aquatic Ecology

–Streams and Wetlands

–Terrestrial Ecology

–Threatened and Endangered Species

–Land Use

–Cultural and Historical Resources

–Socioeconomics

–Environmental Justice

–Transportation Facilities

–Public Health

–Hazardous and Solid Waste

–Noise

–Recreation

–Visual Resources

The EIS evaluated these areas individually for the action and no action alternatives as well as cumulative impacts for past, present and proposed actions. A Record of Decision (ROD) was issued August 8, 1998 by the TVA that detailed the decision to build the Red Hills Mine. The EIS encompasses all areas within the currently approved Surface Mine Control and Reclamation Act (SMCRA) permits.

The results of the geological baseline studies are detailed in Section 6.0 of this report. Additionally, the results of the surface and groundwater baseline studies and geotechnical studies are documented in Sections 7.3 and 7.4, respectively. In addition, the Red Hills Mine completed baseline assessments of the area soils, prime farmlands, land uses, biological resources, threatened and endangered species, and cultural resources which were used to support the mining permits continuously issued by the Mississippi Department of Environmental Quality (MDEQ) since 1998.

17.2 WASTE DISPOSAL, SITE MONITORING AND WATER MANAGEMENT

WASTE DISPOSAL

No processing of lignite occurs at the Red Hills Mine; therefore, no lignite processing or tailing wastes have been or will be generated.

SITE MONITORING

The Red Hills Mine is required to conduct routine groundwater, surface water and soil sampling in accordance with SMCRA and NPDES permit requirements. Surface and groundwater monitoring occur both within the active mine area as well as in adjacent, undisturbed areas upstream and downstream of the active mining operations. Red Hills Mine also conducts routine soil sampling to ensure the reclaimed environment meets regulatory chemical and textural requirements. The water and soil data are submitted to MDEQ in accordance with permit requirements.

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Mississippi Lignite Mining Company – Red Hills Mine

Red Hills Mine will continue to monitor surface water, groundwater, and soils in accordance with all permit requirements until such time mining and reclamation activities are complete and MDEQ has released the entire project from the reclamation performance bond requirements. This release can only happen once Red Hills Mine has quantitatively demonstrated that the reclaimed areas meet performance criteria detailed in the mining permit. Once the reclamation performance bond is released, the Red Hills Mine will have no further site monitoring requirements.

WATER MANAGEMENT

Because rainfall averages more than 55 inches per year, water management is a critical focus at the Red Hills Mine. Prior to initiating mining activities, streams that would otherwise flow through the active mine area are rerouted around the perimeter of the mine. This allows the natural hydrologic balance to be maintained except for stormwater that falls within the footprint of the active mine area. Red Hills manages stormwater by constructing large, strategically located sedimentation ponds. The sedimentation ponds are constructed in accordance with permit requirements to retain a 10-year, 24-hour storm event. Once the retained water meets NPDES water quality requirements, the water is released back into the natural system. The results of the NPDES monitoring are reported monthly to MDEQ through the eDMR system.

17.3 PROJECT PERMITTING REQUIREMENTS

The Red Hills Mine is operating under the state of Mississippi Surface Coal Mining and Reclamation Permits MS-002, Renewal 3 and MS-004. The permits were issued by the Mississippi Department of Environmental Quality (MDEQ) under delegated authority of the United States Department of the Interior, Office of Surface Mining Reclamation Enforcement (OSMRE) under the Surface Mining Control and Reclamation Act (SMCRA).

PERMIT STATUS

In addition to the mining permits, the Red Hills Mine is required to obtain and maintain numerous other regulatory permits and approvals (Table 17.1).


Table 17.1. Red Hills Mine Permit Summary and Status.
	Name and Address of	Identification
Type of Permit	Issuing Authority	Number	Status
State Coal Exploration	Department of Environmental Quality	NA	Issued 08/15/00
License	Office of Geology
	P. O. Box 20307
	Jackson, Mississippi 39289-1307

State Coal Mining Permit	Department of Environmental Quality	MS-002 Renewal 3	Issued 02/13/18
	Office of Geology	MS-004	Issued 02/11/20
	P.O. Box 20307
	Jackson, Mississippi 39289-1307

Mine Identification No.	Mine Safety and Health Administration	No. 22-00690	Issued 08/26/97
	U. S. Department of Labor
	District II
	135 Gemini Circle, Suite 213
	Birmingham, Alabama 35209

State of Mississippi	Department of Environmental Quality	No. MS0054046	Modified 02/11/20
Water Pollution Control	Office of Pollution Control	No. MSR108199	Issued 06/15/20
Permit (includes Mining	P. O. Box 10385
Stormwater Pollution	Jackson, Mississippi 39289-0385

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Mississippi Lignite Mining Company – Red Hills Mine


Prevention Plan)	Issuing Authority: Mississippi Environmental Quality Permit Board

Section 404 Permit	Vicksburg District	No. MVK-2017-257	Issued 3/28/18
	P. O. Box 60		Modified 7/11/18
	Vicksburg, MS 39180-0060	No. MVK-2016-509	Issued 12/21/20

Section 401 State Water	Department of Environmental Quality	NA	Issued by the
Quality Certification	Office of Pollution Control		Commission for
	P. O. Box 10385		USACE
	Jackson, Mississippi 39289-0385
	Issuing Authority: Mississippi Environmental Quality Permit Board

Exclusion for Rubbish	Department of Environmental Quality	NA	Issued 08/25/98
Disposal Activities	Office of Pollution Control
	P. O. Box 10385
	Jackson, Mississippi 39289-0385

Mississippi Conditionally	Department of Environmental Quality	MSR000005330	Issued 3/17/99
Exempt Small Quantity	Office of Pollution Control
Generator	P. O. Box 10385
	Jackson, Mississippi 39289-0385

Spill Prevention Control and	USEPA, Region IV and	NA	Revised 6/11/18
Countermeasure Plan	Department of Environmental Quality
	Office of Pollution Control
	P. O. Box 10385
	Jackson, Mississippi 39289-0385

Dragline Boom	U.S. Department of Transportation	NA	Exemption Request
Height	FAA		Approved 3/3/98
	2300 East Devon Avenue
	Des Plains, Illinois 60018

Radio Station Authorization	Federal Communications Commission	NA	Issued 10/21/2015
	Wireless Telecommunications Bureau


Water Withdrawal Permit	Department of Environmental Quality	No. MS-GW-15160	Well (Issued 8/25/98)
for Beneficial Uses	Office of Land and Water Resources	No. MS-GW-15254	Well (Re-issued 07/16/2018)
for Public Water of the	P. O. Box 10385	No. MS-SW-02755	R-1 (Re-issued 05/12/2008)
State of Mississippi	Jackson, Mississippi 39289-0385	No. MS-SW-02791	P-4-1 (Re-issued 05/12/2008)
		No. MS-SW-10088	RP-33-1 (Issued 4/20/2009)

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Mississippi Lignite Mining Company – Red Hills Mine


		No. MS-SW-10104	P-29-2 (Issued 6/22/2009)
		No. MS-SW-10150	RP-27-1 (Issued 8/23/2010)
		No. MS-SW-10530	SP-8 (Issued 5/4/2020)

Beneficial Use	Department of Environmental Quality	BUD 0015	Issued 12/14/06
Determination (BUD)	Office of Pollution Control	BUD 0099	Issued 05/04/21
	P.O. Box 10385
	Jackson, Mississippi 39289-0631

Handheld XRF Analyzer	Mississippi State Department of Health	No. X-326	Issued 09/08/20
Analytical X-Ray	Division of Radiology
	3150 Lawson Street
	Jackson, Mississippi 39213

Construction on the R-O-W	Mississippi Department of Transportation (MDOT)	1-20-10-0069	Issued 02/21/20
of SR 9 in Choctaw County	P.O. Box 2060
Bridge and Haul Road	Tupelo, Mississippi 38803-2060



Work within TVA Transmission	TVA Transmission R-O-W Team	NA	Issued 03/23/20
Right-of-Way	Tennessee Valley Authority
	400 West Summit Hill Drive
	Knoxville, TN 37902

Road Closures, Relocations	The Choctaw County Board	Prewitt Road	Issued 08/01/2011
and operations within 100'	of Supervisors	State HWY 415	Issued 03/22/04
of Outside Right of Ways	P. O. Box 250	State HWY 415	Issued 03/26/04
	Ackerman, Mississippi 39734
		East Clear Springs Rd.	Issued 03/22/04
		East Clear Springs Rd.	Issued 6/8/2009
		East Clear Springs Rd.	Issued 2012

		McIntire Road	Issued 10/02/05
		McIntire Road	Issued 2012
		McIntire Road	Issued 2013

		Nebo Road	Issued 03/17/03
		Nebo Road	Issued 2013

		Null Road	Issued 10/02/05
		Null Road	Issued 2013

		Salem-Bywy Road	Issued 03/22/04

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Mississippi Lignite Mining Company – Red Hills Mine


	Salem-Bywy Road	Issued 05/24/04
	Salem-Bywy Road	Issued 08/30/04
	Salem-Bywy Road	Issued 04/03/06
	Salem-Bywy Road	Issued 2013
	Salem-Bywy Road	Issued 2015

MDOT	State HWY 415	Issued 03/26/04
Post Office Box 2060	State HWY 9	Issued 02/21/20
Tupelo, Mississippi 38803-2060	State HWY 9	Issued 08/25/21

RECLAMATION BOND REQUIREMENTS

MDEQ regulations require the Red Hills Mine post a reclamation performance bond that would allow MDEQ to affect final reclamation of the project in the unlikely event the Red Hills Mine goes out of business. Bonding is calculated based on a worst-case scenario. The amount of the financial security as of December 31, 2021 is $74 M.

17.4 PLANS, NEGOTIATIONS, OR AGREEMENTS WITH LOCAL INDIVIDUALS OR GROUPS

The Red Hills Mine has secured agreements with all third parties that are necessary to conduct mining operations in accordance with applicable law.

17.5 MINE CLOSURE PLANS

Following the exhaustion of Mineral Reserves, the mine will be required to complete final remediation in accordance with detailed plans in the approved mining permit. Final reclamation and closure activities will begin in the original permit area in 2023 as active mining in this area phases out. Closure activities will continue throughout the mine life, with the projected completion of the expanded permit area in 2041. Financial assurance for the ultimate reclamation of facilities is documented in the reclamation plan, and security for costs that will be incurred to execute site closure is provided by a third-party insurer to the State of Mississippi in the form of a surety bond.

17.6 QP’S OPINION OF ADEQUACY OF CURRENT PLANS

MLMC currently has all permits in place for the Red Hills Mine to operate and adhere to a mine plan projected through 2032. Barring any regulatory changes out of MLMC’s control, the QP does not anticipate hurdles for approval of future renewal applications. The QP bases this opinion on the mine’s history to meet regulatory requirements. No mine permit violations have been issued at the Red Hills Mine in the past ten years. Proper monitoring is ongoing in accordance with permit requirements. Furthermore, appropriate bonding and closure plans are in place.

17.7 DESCRIPTION OF ANY COMMITMENTS TO ENSURE LOCAL PROCUREMENT AND HIRING

Purchasing endeavors to place orders with regards to dependability and service records of the supplier, the nature of the guaranty and warranty of the product, its price, and quality. Preference is given to suppliers who are developing new and improved products or equipment, or designing and developing a special product, specifically for the Red Hills Mine. Consideration is also provided to local suppliers near the Red Hills Mine. Suppliers must have a reputation of adhering to specifications and delivery schedules.

Positions at the Red Hills Mine are posted with Mississippi Department of Employment Security for priority availability to all veterans and other job seekers. MLMC also participates with regional state job fairs, recruits on local college campuses, and participates in local community sponsored activities.

SEC S-K 1300 Technical Report Summary February 2022

Mississippi Lignite Mining Company – Red Hills Mine

18.0 CAPITAL AND OPERATING COSTS

18.1 OPERATING COSTS

Annual operating costs were estimated in conjunction with the mining methods discussed in Section 13.0. LOM operating costs for a plan delivering 27,215,000 MMBtu to the RHPP are expected to total approximately $830 M from January 2022 through the end of the LSA in April 2032 and are summarized Table 18.1.

All costs were estimated to a PFS level of study based on historical costs and performance measures that have been maintained by MLMC since its inception. These costs are reviewed and updated on an annual basis to account for changes in site conditions or the operating plan. This information was then used to estimate the projected future costs included in the LOM plan from January 2022 through the expiration of the LSA in April 2032. All costs were escalated at various rates based on the forward-looking Consumer/Producer Price Index with budgeted 2021 costs used as the base year.

Operating costs included major cost categories for mine development, burden removal, severing of lignite, reclamation, maintenance and handling of stockpiled lignite and delivery to the adjacent RHPP along with the necessary maintenance required to keep all equipment operating safely and efficiently. Direct costs were categorized as expenses directly related to the severing and delivery of lignite. All other general business expenses were categorized as indirect costs. Direct costs included production, maintenance, and staff labor, materials and supplies, fuel, equipment repairs, outside contractors, administration, production taxes and royalties, depletion, depreciation, and amortization (DD&A), inventory adjustments, interest expense, income taxes, and accretion on asset retirement obligations (ARO). Accretion costs are calculated by taking the escalated cash flows of the ARO liability over time and discounting it to its present value as required under U.S. GAAP.

Table 18.1. LOM Operating Costs to deliver 27,215,000 MMBtu per year.

18.2 CAPITAL COSTS

Capital Costs were estimated to a PFS level of study based on vendor quotes, historical land purchases, mine development costs, mitigation costs and other

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Mississippi Lignite Mining Company – Red Hills Mine

costs. Capital costs to fulfil the LSA for a LOM plan delivering 27,215,000 MMBtu per year to the RHPP are expected to total approximately $32 M from January 2022 through the end of the LSA in April 2032 and are summarized in Table 18.2. Consistent with operating costs, all capital costs were escalated at various rates based on the forward-looking Customer/Producer Price Index using 2021 as the base year.

There are risks regarding the estimated capital costs including escalating costs of raw materials, equipment availability or supply chain gaps.

Table 18.2. LOM Capital Costs to deliver 27,215,000 MMBtu per year.

19.0 ECONOMIC ANALYSIS

19.1 KEY ASSUMPTIONS, PARAMETERS AND METHODS

The primary key assumption to determine the economic viability of the Red Hills Mine was the annual operating performance of the RHPP. The forecasted operating performance of RHPP was determined using two main inputs: the annual projection notice (nomination for MMBtu requirements) received from the RHPP based on projected customer requirements and a comparison to prior years actual delivered lignite fuel to develop the expectation for future MMBtu requirements. The estimated annual MMBtu requirement used in the Red Hills LOM Model was 27,215,000 MMBtu. This resulted in a production schedule of approximately 2.7 Mt of dedicated lignite per year and was assumed to continue for the full LSA contract term, expiring in April 2032.

The base price for the dedicated lignite is defined in the LSA. This base price consists of eight indexed components including a power cost component, a pass-through component, a royalty component and a fixed component. Over the LOM, the average estimated sales price per ton for lignite delivered and sold was $28.04 providing revenues totaling approximately $769 M.

Key assumptions and methods used to determine the capital and operating costs associated with the production schedule were detailed previously in Section 18.0 Capital and Operating Costs of this TRS.

Additional key assumptions include:

–The LOM production plan was based primarily on surface mining methods including a truck and shovel, dozer and dragline operations;

–Total number of employees per year was 200, plus temporary employees as needed;

–Diesel price was $1.63 per gallon at the beginning of 2021. This price was escalated based on the NYMEX curve as well as the Producer Price index (wpu057303) to reach $3.96 by 2032;

–Revenue $/MMBtu was escalated using the eight indexed components defined in the LSA;

–The economic analysis period of the Red Hills Mine LOM plan was the remaining production operation from January 1, 2022 until April 2032 plus 13 years of post-mining reclamation;

–$.08/ton sold Reclamation Fee assessed on delivered tons;

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Mississippi Lignite Mining Company – Red Hills Mine

–Discount rate of 10% was used to account for cost of capital and;

12% estimated effective income tax rate. The effective income tax rate of 12% differs from the U.S. federal statutory rate primarily due to the benefit from percentage depletion. The benefit of percentage depletion is not directly related to the amount of pre-tax income recorded in a period.

19.2 ANNUAL CASH FLOWS

The Income Statement and Annual Cash Flows based on the lignite production schedule for the LOM plan, along with the Net Present Value are detailed in Table 19.1. A Discount Rate of 10% was used as this was consistent with the Red Hills Mine’s weighted average cost of capital. The calculation of Net Present Value and Internal Rate of Return are nuanced due to the ongoing nature of this mining operation. As modeled, the cash flows for the period 2022 through 2045 indicate the project is cash flow positive over the remaining life of the project.

In the opinion of the QP, the income statement and cash flow projection based on the LOM plan assumptions as shown in Table 19.1 are reasonable in light of historical trends, current conditions and expected future developments. As modeled, the future cash flow projection is estimated to be approximately $80 M and the net present value is estimated to be approximately $42 M.

Note that the net present value calculated for this report does not consider previous cash inflows and outflows and is only calculated from 2022 through the remainder of the LOM.

Table 19.1. Summary of Income Statement and Cash Flow for LOM plan delivering 27,215,000 MMBtu.

19.3 SENSITIVITY ANALYSIS

Additional LOM scenarios were modeled to analyze the effect of changes in key assumptions. The most significant affect was an increase in the annual MMBtu requirement. Table 19.2 reflects a 15% upside case with an increased annual MMBtu requirement by the RHPP to 31,293,000 MMBtu, which is well within the operating capacity of the RHPP, and results in an increase in total projected after-tax cash flow to $163 M and a Net Present Value of $86 M at a 10% discount rate. Significant risk from a downside case, where the RHPP takes less than the LOM plan MMBtu’s, is protected by a minimum annual take provision included in the LSA.

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Table 19.2. Effect of 15% increase in delivered MMBtu.

Other key assumptions modeled and reviewed were the effects of an increase in diesel prices and labor. A 10% increase in the cost of diesel fuel had an average annual effect of $0.6 M. A 10% increase in the cost of labor had an annual average effect of approximately $1 M. The Red Hills Mine sells coal to the RHPP at a contractually agreed-upon price which adjusts monthly, primarily based on changes in the level of established indices which reflect general U.S. inflation rates. Profitability at MLMC is affected by customer demand for coal and changes in the indices that determine sales price and actual costs incurred.

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20.0 ADJACENT PROPERTIES

There are no other properties adjacent to the Red Hills Mine. There is no information used in this TRS that has been sourced from adjacent properties. No public drilling information was available or sourced for the development of the geological model.

The drilling and exploration activities at the Red Hills Mine well defines the lignite geology, Mineral Resources and Mineral Reserves. Due to this and the relatively simple geology at the Red Hills Mine, material changes to the Mineral Resource estimates and Mineral Reserve estimates are not likely if adjacent property information is included in future estimates.

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21.0 OTHER RELEVANT DATA AND INFORMATION

In the QPs opinion, all material information has been stated in the above sections of this TRS.

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22.0 INTERPRETATIONS AND CONCLUSIONS

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23.0 RECOMMENDATIONS

The QP has no recommendations for additional work outside the scope of the existing LOM plan.

Current work plans that are budgeted in the discounted cash flows (DCF) that the Red Hills Mine will complete include:

–Continue with exploration drilling program (estimated at $1.3M for the LOM plan);

–Monitor pit pore pressures in future in pit areas identified of potential concern (thick AB sands);

–Continue seeking used equipment to reduce capital costs;

–Continue current practices and reconciliations of actual to budget lignite recoveries, qualities and costs;

–Update LOM plan projections and economic analyses accordingly.

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24.0 REFERENCES

Aquaterra Engineering, LLC. (2004, October 27). Geotechnical Investigation.

Aquaterra Engineering, LLC. (2009, April 15). Red Hills Mine Slide Investigation.

Aquaterra Engineering, LLC. (2010, April 15). Red Hills Slope Stability Mitigation Test Plan.

Barr Engineering. (2014, March). Design Report for Red Hills Mine Slope Stability Study.

Burns Cooley Dennis, Inc. (1997, June 23). Preliminary Geotechnical Investigation.

Climate in Ackerman, Mississippi. (2021, June 6). Retrieved from Best Places: https://www.bestplaces.net/climate/city/mississippi/ackerman

CRIRSCO. (2019, November). The International Reporting Template.

Dicken, C. L., Nicholson, S. W., Horton, J. D., Foose, M. P., & Mueller, J. A. (2005). Integrated Geologic Map Databases for the United States: Mississippi. U.S. Geological Survey Open File Report 2005-1323. Reston, VA: U.S. Geological Survey .

FEIS. (1998). Final Environmental Impact Statement . Tennessee Valley Authority.

Geoscience Engineering, LLC. (1997, August 27). Geotechnical Data Report Res Hills Lignite Mine.

Mississippi Lignite Mining Company. (2019, August 19). Red Hills Mine Ground Control Plan.

NACoal. (2020, November 30). 2020 Lignite Coal Quality Round Robin.

Pritchard Engineering, I., & NACoal. (1999, November 5). Stability of Excess Spoil Piles at the Red Hills Mine.

Tittle, D. (2013). Getting the Coal Out. NACCO Industries.

U.S. Department of the Interior. (1989). Methods for Sampling and Inorganic Analysis of Coal. U.S. Geological Survey Bulletin 1823.

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25.0 RELIANCE ON INFORMATION PROVIDED BY THE REGISTRANT

At time of signing, the QPs for this report are employees of the registrant, and all information was sourced from the registrant or studies commissioned by the registrant.

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PROPERTY LOCATION

The Red Hills Mine is an operating lignite surface mine located approximately 7 miles northwest of Ackerman, Mississippi, in Choctaw County, which is approximately 120 miles northeast of Jackson, Mississippi. The entrance to the mine is by means of a paved road that is located approximately 1 mile west of MS Highway 9. The general location of the Red Hills Mine is shown in Figure 1.1 (Location of Red Hills Mine). The RHPP is adjacent to the Red Hills Mine.

SEC S-K 1300 Individual Property Disclosure

Mississippi Lignite Mining Company – Red Hills Mine February 2022

Figure 1.1. Location of the Red Hills Mine.

SEC S-K 1300 Individual Property Disclosure

Mississippi Lignite Mining Company – Red Hills Mine February 2022

LOCAL RESOURCES AND INFRASTRUCTURE

The Red Hills Mine sources power for mine office facilities and operations from 4-County Electric Power Association, and water for the mine office facilities from the Choctaw Water Association. Fuel for equipment is supplied by Dickerson Petroleum located in Kosciusko. The Red Hills Mine has, or is currently constructing, all supporting infrastructure for mining operations.

In additional to transportation via roadways, air and waterways, the Kansas City Southern (KCS) railroad has a depot located approximately 5 miles south of the mine in Ackerman, and is accessible by Highway 9 and Highway 15.

LEASES

The Mississippi Lignite Mining Company (MLMC) owns in fee approximately 7,343 acres of surface interest and 4,425 acres of coal interest. MLMC holds leases granting the right to mine approximately 5,794 acres of coal interests and the right to utilize approximately 5,597 acres of surface interests. MLMC holds subleases under which it has the right to mine approximately 1,593 acres of coal interest.

The name or number and expiration date of each title, claim, mineral right, lease, or option under which MLMC or an affiliated NACCO company has or will have the right to hold or operate on the property is described on Table 1.1 (Identification of Leases) and Table 1.2 (Identification of Acquisitions).

SEC S-K 1300 Individual Property Disclosure

Mississippi Lignite Mining Company – Red Hills Mine February 2022


Table 1.1. Identification of Leases
Lease Id	Lease Type	Lease Date	Lease Expiration Date
955-900002	Coal Lease	12/31/2013	12/30/2038
955-900003	Coal Lease	12/31/2013	12/30/2038
955-900004	Coal Lease	12/31/2013	12/30/2038
955-900005	Coal Lease	12/31/2013	12/30/2038
955-900006	Coal Lease	12/31/2013	12/30/2038
955-900007	Coal Lease	12/31/2013	12/30/2038
955-900008	Coal Lease	12/31/2013	12/30/2038
955-900009	Coal Lease	12/31/2013	12/30/2038
955-900010	Coal Lease	12/31/2013	12/30/2038
955-900011	Coal Lease	12/31/2013	12/30/2038
955-900012	Coal Lease	12/31/2013	12/30/2038
955-900013	Coal Lease	12/31/2013	12/30/2038
955-900014	Coal Lease	12/31/2013	12/30/2038
955-900015	Coal Lease	12/31/2013	12/30/2038
955-900016	Coal Lease	12/31/2013	12/30/2038
955-900017	Coal Lease	12/31/2013	12/30/2038
955-900018	Coal Lease	12/31/2013	12/30/2038
955-900019	Coal Lease	12/31/2013	12/30/2038
955-900023	Coal Lease	7/10/2015	7/9/2040
955-900024	Coal Lease	7/10/2015	7/9/2040
955-900025	Coal Lease	7/10/2015	7/9/2040
955-900026	Coal Lease	7/10/2015	7/9/2040
955-900027	Coal Lease	7/10/2015	7/9/2040
955-900028	Coal Lease	7/10/2015	7/9/2040
955-900029	Coal Lease	7/10/2015	7/9/2040
955-900030	Coal Lease	10/26/2015	10/25/2040
955-900031	Coal Lease	10/26/2015	10/25/2040
955-900032	Coal Lease	5/6/2016	5/5/2041
955-900033	Coal Lease	10/1/2017	9/30/2042
955-900038	Coal Lease	6/1/2019	5/31/2044
956-929484	Coal Lease	5/9/1975	5/8/2025
956-929485	Coal Lease	5/9/1975	5/8/2025
956-929508	Coal Lease	5/14/1975	5/13/2025
956-929557	Coal Lease	5/13/1975	5/12/2025
956-929588	Coal Lease	3/5/1981	3/4/2031
956-929589	Coal Lease	6/16/1975	6/15/2025
956-929597	Coal Lease	6/24/1975	6/23/2025
956-929599	Coal Lease	5/12/1975	5/11/2025
956-929603	Coal Lease	6/26/1975	6/25/2025
956-929646	Coal Lease	6/2/1975	6/1/2025
956-929743	Coal Lease	5/14/1975	5/13/2025
956-929744	Coal Lease	6/11/1975	6/10/2025
956-929745	Coal Lease	6/11/1975	6/10/2025
956-929748	Coal Lease	5/22/1978	5/21/2028

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Mississippi Lignite Mining Company – Red Hills Mine February 2022


956-929749	Coal Lease	8/7/1975	8/6/2025
956-929750	Coal Lease	8/4/1975	8/3/2025
956-929751	Coal Lease	6/17/1975	6/16/2025
956-929752	Coal Lease	6/5/1975	6/4/2025
956-929755	Coal Lease	8/7/1975	8/6/2025
956-929757	Coal Lease	8/25/1975	8/24/2025
956-929759	Coal Lease	8/27/1975	8/26/2025
956-929801	Coal Lease	10/24/1974	10/23/2025
956-929802	Exploration Contract & Coal Lease	10/30/1974	10/29/2025
956-929803	Coal Lease	9/4/1975	9/3/2025
956-929835	Exploration Contract & Coal Lease	10/24/1974	10/23/2025
956-929839	Coal Lease	9/15/1975	9/14/2025
956-929841	Coal Lease	9/15/1975	9/14/2025
956-929842	Coal Lease	9/24/1975	9/23/2025
956-929910	Exploration Contract & Coal Lease	10/11/1974	10/10/2025
956-929911	Exploration Contract & Coal Lease	10/28/1974	10/27/2025
956-929954	Coal Lease	9/22/1975	9/21/2025
956-929955	Coal Lease	9/25/1975	9/24/2025
956-929956	Coal Lease	9/26/1975	9/25/2025
956-929957	Coal Lease	9/20/1975	9/19/2025
956-929958	Coal Lease	10/2/1975	10/1/2025
956-929959	Coal Lease	10/3/1975	10/2/2025
956-930068	Coal Lease	10/13/1975	10/12/2025
956-930187	Coal Lease	10/7/1975	10/6/2025
956-930280	Coal Lease	12/18/1975	12/17/2025
956-930367	Coal Lease	12/16/1975	12/15/2025
956-930413	Coal Lease	2/27/1976	2/26/2026
956-930414	Coal Lease	2/27/1976	2/26/2026
956-930474	Coal Lease	1/26/1976	1/25/2026
956-930480	Coal Lease	2/3/1976	2/2/2026
956-930482	Coal Lease	2/25/1976	2/24/2026
956-930483	Coal Lease	2/19/1976	2/18/2026
956-930488	Coal Lease	3/18/1976	3/17/2026
956-930493	Coal Lease	3/10/1976	3/9/2026
956-930494	Coal Lease	3/17/1976	12/31/2036
956-930495	Coal Lease	3/22/1976	3/21/2026
956-930497	Coal Lease	3/23/1976	3/22/2026
956-930499	Coal Lease	3/18/1976	3/17/2001*
956-930500	Coal Lease	3/8/1976	3/7/2026
956-930501	Coal Lease	3/31/1976	3/30/2026
956-930513	Coal Lease	4/21/1976	4/20/2026
956-930514	Coal Lease	4/21/1976	4/20/2026
956-930515	Coal Lease	4/13/1976	4/12/2026
956-930516	Coal Lease	5/1/1976	4/30/2026
956-930530	Coal Lease	5/4/1976	5/3/2026
956-930593	Coal Lease	3/16/1976	3/15/2026
956-931123	Coal Lease	4/11/1978	4/10/2028

SEC S-K 1300 Individual Property Disclosure

Mississippi Lignite Mining Company – Red Hills Mine February 2022


956-931124	Coal Lease	4/11/1978	4/10/2028
956-931250	Coal Lease	8/14/1978	8/13/2028
956-931266	Coal Lease	1/19/1983	1/18/2008*
956-931267	Coal Lease	1/21/1983	1/20/2008*
956-931308	Coal Lease	6/25/1980	6/24/2030
956-931314	Coal Lease	7/31/1980	7/30/2030
956-931316	Coal Lease	8/12/1980	8/11/2030
956-931317	Coal Lease	9/11/1980	9/10/2030
956-931318	Coal Lease	9/18/1980	9/17/2030
956-931323	Coal Lease	10/8/1980	10/7/2030
956-931395	Coal Lease	7/29/1981	7/28/2031
956-931396	Coal Lease	8/24/1981	8/23/2031
956-931397	Coal Lease	8/24/1981	8/23/2031
956-931398	Coal Lease	2/10/1982	2/9/2032
956-931409	Coal Lease	7/31/1981	7/30/2031
956-931473	Coal Lease	3/25/1982	3/24/2032
956-931474	Coal Lease	3/25/1982	3/24/2032
956-931475	Coal Lease	4/9/1982	4/8/2032
956-931476	Coal Lease	6/28/1982	6/27/2032
956-931477	Coal Lease	6/8/1982	6/7/2032
956-931478	Coal Lease	6/28/1982	6/27/2032
956-931479	Coal Lease	12/2/1982	12/1/2032
956-931480	Coal Lease	12/2/1982	12/1/2032
956-931481	Coal Lease	3/25/1982	3/24/2032
956-931484	Coal Lease	5/10/1982	5/9/2032
956-931485	Coal Lease	5/10/1982	5/9/2032
956-931524	Coal Lease	10/8/1982	10/7/2032
956-931537	Coal Lease	12/13/1982	12/12/2032
956-931577	Coal Lease	5/3/1983	5/2/2008*
956-931579	Coal Lease	5/2/1983	5/1/2008*
956-931640	Coal Lease	7/2/1997	7/1/2047
956-931641	Coal Lease	7/2/1997	7/1/2047
956-931642	Coal Lease	7/11/1997	7/10/2047
956-931643	Coal Lease	7/18/1997	7/17/2047
956-931644	Coal Lease	7/2/1997	7/1/2047
956-931645	Coal Lease	7/2/1997	7/1/2047
956-931646	Coal Lease	7/2/1997	7/1/2047
956-931647	Coal Lease	7/11/1997	7/10/2047
956-931648	Coal Lease	7/18/1997	7/17/2047
956-931649	Coal Lease	7/2/1997	7/2/2047
956-931658	Coal Lease	11/23/1999	11/22/2024
956-931677	Coal Lease	5/17/2000	5/16/2050
956-931705	Coal Lease	7/16/2001	7/15/2026
956-931706	Coal Lease	10/6/2005	10/5/2030
956-931708	Coal Excavation Lease	12/10/2007	12/9/2047
956-931709	Coal Lease	3/22/2010	3/21/2035
956-931710	Coal Lease	5/25/2011	5/24/2061

SEC S-K 1300 Individual Property Disclosure

Mississippi Lignite Mining Company – Red Hills Mine February 2022


956-931711	Coal Lease	12/20/2012	12/19/2062
956-931712	Coal Lease	12/17/2012	12/16/2062
956-931713	Coal Lease	12/20/2012	12/19/2062
956-931714	Coal Lease	9/11/2013	9/10/2063
956-931716	Coal Lease	12/20/2013	12/19/2063
956-931718	Lignite Mining Lease	9/25/2013	9/24/2063
956-931719	Coal Lease	12/20/2013	12/19/2063
956-931723	Coal Lease	4/19/2016	4/18/2066
956-931724	Coal Lease	9/9/2016	9/8/2066
956-931728	Coal & Lignite Lease Agreement	11/14/2017	11/13/2047
956-931729	Coal Lease	11/16/2017	11/15/2067
956-931730	Lignite Mining Lease	12/18/2017	12/17/2067
956-931734	Coal Lease	9/28/2018	9/27/2043
956-931735	Coal Lease	1/23/2019	1/22/2044
956-931737	Coal Lease	3/13/2019	3/12/2069
956-931738	Coal Strip Mining Lease	10/25/2019	10/24/2034
956-931742	Coal Lease	1/31/2021	1/30/2071
956-931743	Coal Lease	6/25/2021	6/24/2071
*Lease continued past expiration by annual payment.


Table 1.2. Identification of Acquisitions
Agreement Id	Agreement Type	Agreement Date	Agreement Expiration Date
957-MLC001	Warranty Deed	8/19/1998	8/18/2097
957-MLC002	Coal Warranty Deed	10/1/1997	12/31/2099
957-MLC003	Warranty Deed	9/17/1998	9/16/2097
957-MLC004	Warranty Deed	12/22/2000	12/21/2999
957-MLC005	Warranty Deed	9/20/2001	9/19/2100
957-MLC006	Warranty Deed	10/12/1998	12/31/2099
957-MLC007	Warranty Deed	10/1/2001	9/30/2100
957-MLC008	Warranty Deed	1/22/2002	1/21/2101
957-MLC009	Warranty Deed	1/22/2002	1/21/2101
957-MLC010	Warranty Deed	10/29/1996	10/28/2096
957-MLC011	Warranty Deed	6/1/1999	6/1/2099
957-MLC012	Warranty Deed	1/5/1999	1/5/2098
957-MLC013	Coal and Lignite Deed	7/8/2005	7/7/2104
957-MLC014	Special Warranty Deed	4/2/1998	4/1/2097
957-MLC015	Special Warranty Deed	8/11/1998	8/10/2097
957-MLC016	Warranty Deed	9/5/1998	12/31/2099
957-MLC017	Warranty Deed	1/24/2000	1/24/2099
957-MLC018	Warranty Deed	8/19/1998	8/19/2097
957-MLC019	Warranty Deed	1/24/2000	1/23/2099
957-MLC020	Warranty Deed	8/17/1998	8/16/2098
957-MLC021	Warranty Deed	6/30/1998	6/29/2097
957-MLC022	Warranty Deed	3/11/1998	3/10/2098
957-MLC023	Warranty Deed	2/25/2003	2/24/2102

SEC S-K 1300 Individual Property Disclosure

Mississippi Lignite Mining Company – Red Hills Mine February 2022


957-MLC024	Warranty Deed	11/10/1998	11/9/2097
957-MLC025	Warranty Deed	11/24/1998	11/23/2097
957-MLC026	Warranty Deed	5/14/1999	5/13/2098
957-MLC027	Warranty Deed	4/8/1999	4/7/2098
957-MLC028	Warranty Deed	4/22/1999	4/22/2999
957-MLC029	Warranty Deed	7/7/1999	7/6/2098
957-MLC030	Warranty Deed	5/2/2003	5/1/2102
957-MLC031	Warranty Deed	5/5/2003	5/4/2102
957-MLC032	Warranty Deed	5/2/2003	5/1/2102
957-MLC033	Warranty Deed	7/8/2003	7/7/2102
957-MLC034	Warranty Deed	3/17/2004	12/31/2099
957-MLC035	Warranty Deed	7/16/2004	7/15/2103
957-MLC036	Warranty Deed	11/15/2004	12/31/2999
957-MLC037	Warranty Deed	2/18/2005	12/31/2999
957-MLC038	Warranty Deed	2/23/2005	2/22/2104
957-MLC039	Warranty Deed	4/8/2005	4/7/2104
957-MLC040	Warranty Deed	2/28/2006	2/27/2105
957-MLC041	Warranty Deed	6/28/2007	6/28/2106
957-MLC042	Warranty Deed	7/26/2006	7/25/2105
957-MLC043	Warranty Deed	10/28/2006	10/27/2105
957-MLC044	Warranty Deed	10/28/2006	10/27/2105
957-MLC045	Warranty Deed	10/27/2006	10/26/2105
957-MLC046	Warranty Deed	8/1/2007	7/31/2106
957-MLC047	Warranty Deed	11/20/2007	11/19/2106
957-MLC048	Special Warranty Deed	11/7/2007	11/6/2106
957-MLC049	Warranty Deed	11/26/2007	11/25/2106
957-MLC050	Warranty Deed	6/13/2008	12/31/2099
957-MLC051	Warranty Deed	9/4/2008	12/31/2099
957-MLC052	Warranty Deed	4/23/2009	12/31/2999
957-MLC053	Warranty Deed	12/21/2010	12/31/2999
957-MLC054	Warranty Deed	5/25/2011	12/31/2999
957-MLC055	Special Warranty Deed	6/27/2011	12/31/2999
957-MLC056	Special Warranty Deed	7/3/2011	12/31/2999
957-MLC057	Special Warranty Deed	7/8/2011	12/31/2999
957-MLC058	Warranty Deed	10/13/2011	12/31/2999
957-MLC059	Warranty Deed	10/13/2011	12/31/2999
957-MLC060	Warranty Deed	12/30/2011	12/31/2999
957-MLC061	Warranty Deed	7/17/2012	12/31/2099
957-MLC062	Warranty Deed	7/13/2012	12/31/2099
957-MLC063	Warranty Deed	7/13/2012	12/31/2099
957-MLC064	Warranty Deed	9/20/2012	12/31/2099
957-MLC065	Warranty Deed	12/6/2012	12/31/2999
957-MLC066	Warranty Deed	12/6/2012	12/31/2099
957-MLC067	Warranty Deed	12/3/2012	12/31/2099
957-MLC068	Warranty Deed	4/3/2013	12/31/2099
957-MLC069	Warranty Deed	12/20/2012	12/31/2099
957-MLC070	Warranty Deed	12/17/2012	12/31/2099

SEC S-K 1300 Individual Property Disclosure

Mississippi Lignite Mining Company – Red Hills Mine February 2022


957-MLC071	Warranty Deed	12/14/2012	12/31/2099
957-MLC072	Warranty Deed	12/14/2012	12/31/2099
957-MLC073	Warranty Deed	12/20/2012	12/31/2099
957-MLC074	Warranty Deed	12/20/2012	12/31/2099
957-MLC075	Warranty Deed	10/5/2012	12/31/2099
957-MLC076	Warranty Deed	4/3/2013	12/31/2099
957-MLC077	Warranty Deed	5/3/2013	12/31/2099
957-MLC078	Warranty Deed	6/13/2013	12/31/2999
957-MLC079	Warranty Deed	6/14/2013	12/31/2099
957-MLC080	Warranty Deed	9/11/2013	12/31/2099
957-MLC081	Special Warranty Deed	12/31/2013	12/31/2999
957-MLC082	Special Warranty Deed	12/31/2013	12/31/2099
957-MLC084	Warranty Deed	12/20/2013	12/31/2099
957-MLC085	Quit Claim Deed	7/10/2015	12/31/2099
957-MLC086	Quit Claim Deed	7/10/2015	12/31/2999
957-MLC087	Quit Claim Deed	7/10/2015	12/31/2099
957-MLC088	Warranty Deed	12/20/2013	12/31/2999
957-MLC089	Quit Claim Deed	7/10/2015	12/31/2099
957-MLC091	Quit Claim Deed	7/10/2015	12/31/2099
957-MLC092	Quit Claim Deed	7/10/2015	12/31/2099
957-MLC094	Quit Claim Deed	7/10/2015	12/31/2099
957-MLC095	Quit Claim Deed	7/10/2015	12/31/2099
957-MLC096	Quit Claim Deed	10/26/2015	12/31/2099
957-MLC097	Quit Claim Deed	10/26/2015	12/31/2099
957-MLC098	Quit Claim Deed	10/26/2015	12/31/2099
957-MLC099	Quit Claim Deed	5/6/2016	12/31/2099
957-MLC100	Quit Claim Deed	9/1/2016	12/31/2099
957-MLC101	Quit Claim Deed	9/1/2016	12/31/2099
957-MLC102	Quit Claim Deed	9/1/2016	12/31/2099
957-MLC103	Quit Claim Deed	6/1/2017	12/31/2099
957-MLC109	Quit Claim Deed	10/1/2017	12/31/2099
957-MLC111	Quit Claim Deed	6/1/2019	12/31/2099
957-MLC112	Quit Claim Deed	4/1/2020	12/31/2099
609-RML061	Warranty Deed	12/31/2013	12/31/2099
609-RML062	Warranty Deed	12/31/2013	12/31/2099
609-RML063	Warranty Deed	12/31/2013	12/31/2099
609-RML064	Warranty Deed	12/31/2013	12/31/2099
609-RML065	Warranty Deed	12/31/2013	12/31/2999
609-RML066	Warranty Deed	12/31/2013	12/31/2099
609-RML067	Warranty Deed	12/31/2013	12/31/2099
609-RML068	Warranty Deed	12/31/2013	12/31/2099
609-RML069	Warranty Deed	12/31/2013	12/31/2099
609-RML070	Warranty Deed	12/31/2013	12/31/2099
609-RML071	Warranty Deed	12/31/2013	12/31/2099
609-RML072	Warranty Deed	12/31/2013	12/31/2099
609-RML073	Warranty Deed	12/31/2013	12/31/2099
609-RML074	Warranty Deed	12/31/2013	12/31/2099

SEC S-K 1300 Individual Property Disclosure

Mississippi Lignite Mining Company – Red Hills Mine February 2022


609-RML075	Warranty Deed	12/31/2013	12/31/2099
609-RML076	Warranty Deed	12/31/2013	12/31/2099
609-RML077	Warranty Deed	12/31/2013	12/31/2099
609-RML078	Warranty Deed	12/31/2013	12/31/2999
609-RML079	Warranty Deed	12/31/2013	12/31/2099
609-RML080	Warranty Deed	12/31/2013	12/31/2099
609-RML081	Warranty Deed	9/10/2013	12/31/2999
609-RML082	Warranty Deed	9/10/2013	12/31/2099
609-RML084	Warranty Deed	7/10/2015	12/31/2099
609-RML085	Warranty Deed	12/20/2013	12/31/2099
609-RML086	Warranty Deed	12/20/2013	12/31/2999
609-RML087	Warranty Deed	12/20/2013	12/31/2099
609-RML088	Warranty Deed	12/20/2013	12/31/2999
609-RML089	Warranty Deed	12/20/2013	12/31/2099
609-RML091	Warranty Deed	2/21/2014	12/31/2099
609-RML092	Warranty Deed	7/21/2014	12/31/2099
609-RML094	Warranty Deed	10/16/2014	12/31/2099
609-RML095	Warranty Deed	2/19/2015	12/31/2099
609-RML096	Quit Claim Deed	6/8/2015	12/31/2099
609-RML097	Warranty Deed	6/25/2015	12/31/2099
609-RML098	Warranty Deed	6/25/2015	12/31/2099
609-RML099	Warranty Deed	8/12/2015	12/31/2099
609-RML100	Warranty Deed	4/8/2016	12/31/2099
609-RML101	Warranty Deed	4/8/2016	12/31/2099
609-RML102	Warranty Deed	5/8/2016	12/31/2099
609-RML103	Warranty Deed	9/9/2016	12/31/2099
609-RML104	Warranty Deed	2/11/2017	12/31/2099
609-RML105	Warranty Deed	5/26/2017	12/31/2099
609-RML106	Warranty Deed	6/14/2017	12/31/2099
609-RML107	Warranty Deed	6/28/2017	12/31/2099
609-RML108	Warranty Deed	7/28/2017	12/31/2099
609-RML109	Warranty Deed	8/23/2017	12/31/2099
609-RML110	Warranty Deed	8/28/2017	12/31/2099
609-RML111	Warranty Deed	10/10/2017	12/31/2099
609-RML112	Special (Limited) Warranty Deed	12/21/2017	12/31/2099
609-RML113	Warranty Deed	1/26/2018	12/31/2099
609-RML114	Warranty Deed	1/23/2018	12/31/2099
609-RML115	Warranty Deed	3/16/2018	12/31/2099
609-RML116	Warranty Deed	6/18/2020	12/31/2099
609-RML117	Warranty Deed	11/28/2018	12/31/2099
609-RML118	Warranty Deed	3/21/2019	12/31/2099
609-RML119	Warranty Deed	3/21/2019	12/31/2099
609-RML120	Warranty Deed	6/4/2019	12/31/2099
609-RML121	Warranty Deed	12/30/2019	12/31/2099
609-RML122	Warranty Deed	2/26/2020	12/31/2099
609-RML123	Warranty Deed	7/17/2020	12/31/2099
609-RML124	Warranty Deed	12/10/2020	12/31/2099

SEC S-K 1300 Individual Property Disclosure

Mississippi Lignite Mining Company – Red Hills Mine February 2022


609-RML125	Warranty Deed	1/11/2021	12/31/2099
609-RML126	Warranty Deed	6/15/2021	12/31/2099
609-RML127	Warranty Deed	9/3/2021	12/31/2099
609-RML128	Warranty Deed	11/18/2021	12/31/2099
609-RML129	Warranty Deed	12/23/2021	12/31/2099

SEC S-K 1300 Individual Property Disclosure

Mississippi Lignite Mining Company – Red Hills Mine February 2022

MINE HISTORY, OPERATIONS AND ENCUMBRANCES

MLMC, a subsidiary of the North American Coal Corporation (NACoal) is the owner and operator of the Red Hills Mine. The Red Hills Mine is a lignite surface mine in production. Prior to MLMC, there were no previous mining operations on the Red Hills Mine property.

MLMC was formed as a joint venture between Phillips Coal Company (Phillips), a subsidiary of the Phillips Petroleum Company, and NACoal in 1997. In October 2000, NACoal acquired certain 100% of MLMC.

Original exploration of the Red Hills Mine area was conducted by Phillips from 1975 to 1980. Phillips contracted independent drilling services to drill and geophysically log over 800 boreholes. The data collected from the Phillips’ drilling exploration was the basis of the Red Hills Project, a mine-mouth operation, including the Red Hills Mine and the RHPP. The next drilling campaign was conducted in 1997. Since 1997, regular fill-in drilling programs have been ongoing with the active mining operation.

The geology encountered at the Red Hills Mine is stratigraphic in nature with depositional sequences of sands, silts, clays, and lignite. The vertical repetition of geologic strata facilitated a straightforward setting to establish and study the baseline geological, geochemical, geotechnical, and geohydrological conditions at the Red Hills Mine.

Development of the Red Hills Mine began in 1997, with full commercial deliveries commencing in 2002. The mining operation is comprised of four major equipment fleets. Primary removal of burden is achieved with one 82-cubic yard electric-powered dragline, four large track-type push dozers, and a truck and shovel fleet utilizing a 41-cubic yard electric rope shovel. Lignite is mined using a surface miner or a hydraulic backhoe to load a fleet of end dump haul trucks, and is directly shipped to the RHPP or the lignite stockpile. The overall average quality of the mined lignite seams meets the required power plant quality specifications. Therefore, no mineral processing is performed by MLMC.

The mine office facilities and original equipment fleets at the Red Hills Mine were constructed, acquired, or purchased new during the development stage of the mine. The facilities and equipment are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, MLMC evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.

The total cost of the property and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2021 is $62.5 Million.

MINERAL RESOURCES AND RESERVES

MINERAL RESOURCES

The Mineral Resources presented in Table 1.3 blow have been estimated by applying a series of geologic and physical limits as well as high-level mining and economic constraints. The mining and economic constraints were limited to a level sufficient to support reasonable prospect for future economic extraction of the estimated Mineral Resources. The categorized Mineral Resources reported herein are exclusive of in-situ Mineral Reserves.

The effective date of Mineral Resource estimates is December 31, 2021.

SEC S-K 1300 Individual Property Disclosure

Mississippi Lignite Mining Company – Red Hills Mine February 2022

Table 1.3. Mineral Resources

MINERAL RESERVES

The effective date of Mineral Reserve estimates is December 31, 2021.

Table 1.4. Mineral Reserves

SEC S-K 1300 Individual Property Disclosure

Mississippi Lignite Mining Company – Red Hills Mine February 2022

DISCUSSION OF PRIOR RESOURCE AND RESERVE ESTIMATIONS

Previously, Mineral Reserves for the Red Hills Mine were reported following Guide 7 guidance. All controlled tonnage that met the general mining parameters were considered for reserves and subdivided based on whether an area was currently permitted for mining or not. Mineral Resources were not considered. Furthermore, subcategories of Mineral Resources as measured, indicated, or inferred and Mineral Reserves as proven or probable were not considered.

Table 1.5 below summarizes the Mineral Reserves reported under Guide 7 guidance at the end of the last two fiscal years.


Report Date	Committed Tons*	Uncommitted Tons**	Total Tons
January 1, 2021	161,020,544	76,306,957	237,327,501
January 1, 2020	105,969,007	134,118,244	240,087,251
*Committed tons were defined as controlled tons which fell within the Life-of-Mine (LOM) permit boundary.
**Uncommitted tons were defined as controlled tons which fell outside the LOM permit boundary. ^ The difference in allotment of tons to each category from 2020 to 2021 was due to the permit approval for a new mine area (SMCRA permit MS-004).

Table 1.5. Summary of Prior Mineral Reserves


Red Hills Mine	Tonnage
Resource Classification	December 31, 2021	January 1, 2021	Percent Change
Measured	11,475,500	N/A	N/A
Indicated	16,169,100	N/A	N/A
Measured + Indicated	27,644,600	N/A	N/A
Inferred	0	N/A	N/A

Reserve Classification	December 31, 2021	January 1, 2021	Percent Change
Proven	17,167,900	N/A	N/A
Probable	9,477,600	N/A	N/A
Proven + Probable	26,615,500	237,327,501	-88.8%

Table 1.6. Net difference of reported Mineral Resources and Mineral Reserves from previous reporting period to current reporting period.

Explanation of discrepancies. The primary cause for such a large variance between Mineral Resources and Mineral Reserves from January 1, 2021 to the current report date is due to a change in methodology in categorization of Mineral Resources and Reserves from an interpretation of Guide 7 regulations to following Subpart S-K 1300 regulations. Tighter interpretations and guidance of the S-K 1300 regulations narrowed the basis of Mineral Resources and furthermore Mineral Reserves such that a Mineral Resource is defined as:

“A concentration or occurrence of material of economic interest in or on the Earth’s crust in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. A Mineral Resource is a reasonable estimate of mineralization, taking into account relevant factors, such as cut-off grade, likely mining dimensions, location, or continuity, that, with the assumed and justifiable technical and economic conditions, is likely to, in whole or in part, become economically extractable. It is not merely an inventory of all mineralization drilled or sampled.”

SEC S-K 1300 Individual Property Disclosure

Mississippi Lignite Mining Company – Red Hills Mine February 2022

And a Mineral Reserve is defined as:

“The economically mineable part of a measured or indicated Mineral Resource, which includes diluting materials and allowances for losses that may occur when the material is mined or extracted.”

Additional impacts to the variance in reported Mineral Resources and Reserves from the previous report date to the current report date include:

–MLMC mined 3,197,478 tons in 2021.

MATERIAL ASSUMPTIONS FOR MINERAL RESOURCES AND MINERAL RESERVES

Material assumptions and criteria used in the determination of Mineral Resource and Mineral Reserves reported herein are provided within the filed Technical Report Summary (TRS) for the Mississippi Lignite Mining Company – Red Hills Mine dated February 2, 2022.

SEC S-K 1300 Internal Controls Disclosure

Mississippi Lignite Mining Company – Red Hills Mine January 2022

EXPLORATION DRILLING - GENERAL

Independent drilling companies are contracted by the Mississippi Lignite Mining Company (MLMC) to drill/retrieve coal cores for the Red Hills Mine. MLMC personnel oversee the retrieval of core samples, then log and properly bag those samples for analysis by a certified independent laboratory, Standard Laboratories Inc. (Standard) located in Casper, Wyoming.

For the purpose of this discussion, senior geologist and field geologist refer to qualified representatives of MLMC and/or the North American Coal Corporation (NACoal).

QUALITY CONTROL AND QUALITY ASSURANCE PROGRAMS

SAMPLE PREPARATION

Core runs are specified by the senior and/or field geologist. Once a specified core run is brought to the surface, the field geologist observes the drillers extract the lignite sample from the double barrel core to ensure the integrity of the sample is maintained, and to verify the top and the bottom of the coal core run. The core sample is transferred from the core barrel to a core cradle and is carried to the field geologist’s work station. The field geologist washes excess drilling mud from the core sample with water, verifies the roof and floor of the lignite core is present and checks the expected coal seam thickness to determine coal core recovery. Typically, coal cores from the drilling campaigns at the Red Hills Mine are fully recovered. The minimum core recovery accepted is 90-percent. If accepted recovery is not achieved, the driller may attempt to retrieve the remainder of the lignite core run from the current hole. If no successful attempt is made to recover the remaining lignite, the driller must recore the lost interval in a new adjacent core hole.

Upon verifying acceptable recovery of the core run, the field geologist succinctly, but thoroughly logs the lignite run. After the field geologist describes the core run, the entire lignite section is double bagged and double tagged. Tags include the date, mine identifier, hole ID, seam ID, and “to” and “from” intervals. Double bagging helps to preserve the moisture of the sample, and double tagging safeguards the identification of the sample from the field through transportation to the independent laboratory, Standard Laboratories.

The prep room at Standard is a temperature-controlled room (AC and Heat) accessible from the receiving dock. Within the prep room samples are crushed to 8-mesh size using a Holmes crusher and are then run through a Holmes riffler. Pulverizer screens and rifflers are inspected daily, before and after each batch. The distance between the riffler fin spread is regularly checked in accordance with ASTM standards. An air hose is used to clean out after each sample to mitigate contamination.

Prepared 1000 g trays are placed in one of three air dry units for overnight drying following a modified ASTM method for Total Moisture. Due to lignite having a higher moisture content and faster oxidation rate than higher rank coals, the temperature limit for air-drying was modified to reduce the drying time. In controlled testing, minimal to no evidence of bias was noted in any of the parameters (TM, Dry Ash, AR BTU/lb, MAF Btu) in any of the drying times and temperature combinations. Drying time and temperatures are regulated on the air-dry units. Certified thermometers are used which also indicate minimum and maximum temperature values to ensure there is no exceedance of the max allowable temperature. Temperature gauges are certified annually, and additional checks are performed quarterly.

Once air-drying is complete and samples are re-weighed and logged. Dried samples are pulverized to 60-mesh and splits are obtained with a Holmes riffler. Splits are stored in pre-labeled HDPE bottles with foam lined caps. Prior to any further testing, 60-mesh split bottles are run through a mixing wheel for 10 minutes to ensure a homogeneous sample.

SEC S-K 1300 Internal Controls Disclosure

Mississippi Lignite Mining Company – Red Hills Mine January 2022

CONTROLS

Retained samples. Total core runs are double bagged and double tagged following industry standards for quality analyses, thus split samples in the context of a retained sample are not stored at the Red Hills Mine. As such, any retained samples, including 8-mesh and 60-mesh, are stored at Standard, and collected after total core runs have been crushed and mixed. Additionally, it is important to note that lignites tend to be high moisture coals which oxidize rapidly and do not have a long shelf life once removed from the ground. If core splits were retained at Red Hills Mine, they would not be representative of in-situ coal properties over a relatively short period of time.

Duplicate samples. During the lab analyses Standard runs regular control measures. For calorific value, moisture and ash analyses one duplicate sample as well as one quality control (QC) reference material is ran for every twenty samples. For sulfur analyses, one duplicate sample and one QC reference material is run every ten samples. Laboratory technicians regularly review and record results of tests, but in addition, all machines maintain records of processes and results.

Balances. All balances in use at Standard are calibrated and certified annually by an accredited third-party service. Internal balance checks using certified weights are performed daily, at 3 am, on all balances within the lab and are logged. Employees are notified of the balance check via a white board and must sign off that they have been notified prior to starting work. Additional balance checks are regularly performed by lab technicians during the work day using certified weights.

Round Robin Programs and Control Training. Standard participates in a monthly round robin coal program including 32 other laboratories. A 4-mesh program and an 8-mesh program are included in this round robin. In 2020, Standard also participated in a lignite (coal) specific round robin testing program facilitated by NACoal including 8 commercial laboratories that were used by various NACoal mine locations. The round robin consisted of four samples labeled 2001, 2002, 2003, and 2004. Two samples were sourced from Red Hills Mine and two samples were sourced from another NACoal mine. The two locations provided a range of samples with variability in moisture, ash, sulfur and sodium. The labs participating in the round robin were provided 8-mesh splits and dried 60-mesh splits of all 4 samples. The general results are summarized in Figure 1.0. Standard is labeled “Laboratory #6” and all results fell within ASTM Range.

Figure 1.0. NACoal 2020 Round Robin Program Summary. (NACoal, 2020)

SEC S-K 1300 Internal Controls Disclosure

Mississippi Lignite Mining Company – Red Hills Mine January 2022

CUSTODY

Core samples remain under the supervision of the field geologist until securely stored in the senior geologist’s office or transferred to the warehouse to be shipped to the third-party laboratory, Standard. The Red Hills Mine office facilities are climate controlled and secured with user specified fob access and camera surveillance.

Prior to shipping the samples to Standard, the senior geologist reviews each sample against the field records and the chain-of-custody (COC). The date, mine identifier, hole ID, seam ID, and “to” and “from” intervals are verified. In addition to the COC included in the physical shipping container, a copy is emailed to the laboratory manager to notify that a shipment is in route. Copies of the COC forms for coal cores shipped from 2015 through 2021 were available for the QP to review. Coal core samples are shipped to Standard via insured freight with tracking information.

Once a shipment is received by Standard, it is logged and opened then the number of samples are logged along with the date and time. Each individual sample is cross referenced with the COC and are then weighed using certified balances. Paper records including Standard lab logs, COC’s, and any additional paperwork received in the shipment are transferred to an electronic database at this point.

Once samples are logged they are stored in the receiving room which is climate controlled (ventilation and heat) until there is available space in the prep room; typically, a short period. MLMC acknowledges a slight potential for moisture loss during this storage period and, as such, double bags samples in the field to preserve as much in-situ moisture as possible.

During non-operational hours, Standard’s building is locked down with an active alarm system including door, window and motion detectors which is monitored by a local company. No dogs are onsite that may cause disturbance or destruction (chew/rip open) of samples.

Any additional 8-mesh sample material not required to be dried and pulverized for requested analyses is placed in a bag which then has the air mechanically removed and heat sealed for storage. Excess dried, 60-mesh, material is retained in HDPE bottles with foam lined caps. Retained samples can be reran for analysis within 6-months for selective parameters. Standard verifies with MLMC prior to disposal of splits and retained samples.

QUALITY PRECISION AND ACCURACY

Prior to releasing results of requested analyses, Standard’s laboratory manager or assistant manager reviews all analytical results for anomalies and outliers. This includes mis-type or mis-printed information, and comparison with historical coal core data on record with Standard. Any questionable results are rerun from retained samples.

Once results are received by MLMC, a visual inspection of results by the senior geologist is followed by a review of summary statistics with the quality of the entire drilling database. Ultimately the results are updated in the geologic model and quality grids are inspected for anomalies. At any point if questionable data is traced back to the laboratory report, the senior geologist may request the lab to rerun a retained sample.

The analytical results from the coal cores collected during MLMC’s exploration programs have proven to be consistent with actual as-delivered quality from the active mining operations at the Red Hills Mine. This consistency is based on comparison of historical quality projected from the geologic model for the annual operating plans to actual as-delivered quality indicated by the customer’s third-party laboratory, Advanced Analytical Laboratories.

SEC S-K 1300 Internal Controls Disclosure

Mississippi Lignite Mining Company – Red Hills Mine January 2022

VERIFICATION OF ANALYTICAL PROCEDURES

The QP visited the third-party laboratory on June 24, 2021. During the visit the laboratory manager provided a tour of the full facility from the main offices through the receiving dock/storage room, prep room, and primary laboratory. Observed procedures for calorific value, ash, moisture and sulfur aligned with ASTM standards. Modification to the ASTM standard for Total Moisture was discussed with the laboratory manager and a handout provided. The QP noted the facility was well maintained, and clean of residue that may cause concern for contamination, including the prep room where crushing and pulverizing of materials took place. Quality control training was documented, and the results of the latest, monthly QAR PTP was posted on the white board located in a central location for review. Further details of this specific site visit are discussed in section 8.0 of the Technical Report Summary (TRS) for Mississippi Lignite Mining Company – Red Hills Mine, dated February 2, 2022.

COMPREHENSIVE RISK INHERENT IN THE ESTIMATION OF MINERAL RESOURCES AND RESERVES

Although MLMC has remained consistent with coal core sampling programs following and documenting procedures that align with coal industry there are still some inherent risks in the estimation of Mineral Resources and Reserves. This risk falls in the uncertainty within the early Phillips data collected in the 1970’s and 1980’s. It is understood that the coal cores were sampled and analyzed as total coal runs. However, the exact method in which samples were bagged, shipped, or analyzed are unknown. MLMC acquired the drill hole data and quality results from Phillips, but no documentation on survey standards or QA/QC parameters. MLMC has mitigated this risk by twinning older Phillip’s coal core holes, and verifying modeled trends as mining, and subsequently drilling programs, progress. Verification of lignite quality and trends with newer drilling data reconciliation data has increased the confidence in the early data, but does not eliminate the inherent risk from lack of QA/QC parameters in this small percentage of data.

Cash Flow Summaries

Total Year Oil ------ Mbbl Residue Gas ------ MMcf ------ NGL ------- Mbbl ------- Oil ------- Mbbl ------- Gas ----- MMcf----- ------ Net Reserves Volume -------------- Estimated 8/8 Prod. ------- NGL - $/bbl - Oil - $/bbl - Production and Economic Projection As of: 1/1/2022 Wells Res. Gas - $/Mcf - ---------- Plant Net Sales Volume Wet Gas ------ Mbbl ------ 22,700.74 31.84 3,892.14 193,959.60 52.04 25.55 3.20 65.402022 866 4,032.88 14,943.50 20.44 2,452.90 128,743.66 37.10 25.55 3.21 65.372023 865 2,547.08 10,682.23 14.54 1,737.53 92,805.45 28.04 25.52 3.21 65.352024 863 1,807.22 8,372.99 11.35 1,304.31 71,628.46 21.99 25.51 3.21 65.352025 861 1,358.81 6,900.69 9.34 1,024.19 57,869.23 17.79 25.51 3.21 65.342026 858 1,068.54 5,860.33 7.92 828.69 48,126.28 14.73 25.51 3.21 65.342027 856 865.75 5,096.30 6.88 687.77 41,010.88 12.47 25.52 3.21 65.352028 852 719.46 4,479.01 6.04 577.69 35,367.88 10.65 25.53 3.20 65.352029 849 605.04 3,996.49 5.38 494.03 31,009.27 9.23 25.53 3.20 65.352030 846 518.01 3,602.14 4.85 427.65 27,490.73 8.09 25.54 3.20 65.352031 842 448.89 3,280.73 4.42 374.94 24,662.72 7.17 25.55 3.20 65.352032 840 393.97 2,986.74 4.02 329.20 22,150.70 6.36 25.56 3.20 65.352033 837 346.26 2,735.40 3.67 291.72 20,069.37 5.70 25.57 3.20 65.352034 834 307.14 2,510.38 3.36 260.63 18,259.95 5.14 25.57 3.20 65.352035 832 274.62 2,312.08 3.10 232.72 16,633.34 4.66 25.59 3.20 65.352036 827 245.47 23,358.48After 152,670.02 30.51 1,702.46 41.17 Total 254,875.23 2,659,703.71Ult. 123,818.21 982,457.51 167.65 282.31 16,618.57 Cum. Sub-T 25.55 3.20 65.36 25.65 3.18 65.37 100,459.73 829,787.49 137.14 241.15 14,916.11 65.36 25.54 3.21 0.00% Lease Shrinkage and 4.26% Plant Shrinkage 1,677,246.20 131,057.02 17,358.59 1,819.44 15,539.15 Gas ------ M$ ------ Oil ------ M$ ------ Other ------ M$ ------ Year ----------------------------------- Company Future Gross Revenue ---------------------------------- NGL ------ M$ ------ Total ------ M$ ------ Prod Tax ------ M$ ------ Adv Tax ------ M$ ------ after Sev & Adv ------- M$ -------- ------- Prod & Adv Taxes ----- Revenue 2,082.06 1,329.67 12,463.26 0.00 15,874.99 360.57 820.03 14,694.392022 1,336.22 947.99 7,868.95 0.00 10,153.17 232.09 541.17 9,379.902023 950.14 715.49 5,576.33 0.00 7,241.96 166.43 391.52 6,684.002024 741.96 560.89 4,185.90 0.00 5,488.75 127.85 297.82 5,063.092025 610.11 453.70 3,286.01 0.00 4,349.83 102.68 235.69 4,011.462026 517.34 375.80 2,657.75 0.00 3,550.90 84.94 191.73 3,274.222027 449.39 318.13 2,204.87 0.00 2,972.39 72.03 159.78 2,740.582028 394.58 271.77 1,851.31 0.00 2,517.66 61.78 134.63 2,321.252029 351.87 235.71 1,582.55 0.00 2,170.13 53.88 115.41 2,000.842030 316.99 206.57 1,369.36 0.00 1,892.91 47.41 100.12 1,745.382031 288.55 183.14 1,200.10 0.00 1,671.78 42.29 87.94 1,541.542032 262.41 162.68 1,053.19 0.00 1,478.28 37.79 77.32 1,363.172033 239.84 145.85 932.80 0.00 1,318.49 34.04 68.59 1,215.872034 219.79 131.46 833.29 0.00 1,184.54 30.82 61.34 1,092.392035 202.33 119.19 743.99 0.00 1,065.50 27.99 54.92 982.592036 1,994.25 5,419.22After Total 10,957.83 7,214.18 53,228.88 0.00 0.00 1,056.13 Sub-T 71,400.88 8,469.61 1,733.81 251.22 3,739.37 401.35 65,927.70 7,817.03 8,963.57 6,158.05 47,809.66 0.00 62,931.28 1,482.59 3,338.02 58,110.67 Cumulative ------- M$ ------- Annual ------ M$ ------ Disc. Cum. Annual @ 10.00% ------- M$ ------- -------------------- Future Net Income Before Income Taxes ------------------------------------------------------- Deductions Trans. Costs ------ M$ ------ Net Investments ------ M$ ------ Lease Net Costs ------ M$ ------ Net Profits ------ M$ ------ Undiscounted Discounted Ann @ 10.00% -------M$ ------- Year 2022 0.00 0.00 2,126.10 0.00 12,568.29 12,035.69 12,035.69 12,568.29 2023 0.00 0.00 1,347.94 0.00 8,031.96 6,985.94 19,021.63 20,600.25 2024 0.00 0.00 956.10 0.00 5,727.90 4,525.68 23,547.31 26,328.15 2025 0.00 0.00 719.32 0.00 4,343.77 3,118.58 26,665.89 30,671.92 2026 0.00 0.00 565.50 0.00 3,445.96 2,248.66 28,914.55 34,117.88 2027 0.00 0.00 458.00 0.00 2,816.22 1,670.42 30,584.97 36,934.11 2028 0.00 0.00 380.48 0.00 2,360.11 1,272.34 31,857.30 39,294.21 2029 0.00 0.00 320.02 0.00 2,001.23 980.60 32,837.91 41,295.44 2030 0.00 0.00 273.92 0.00 1,726.92 769.24 33,607.14 43,022.36 2031 0.00 0.00 237.32 0.00 1,508.06 610.67 34,217.81 44,530.43 2032 0.00 0.00 208.25 0.00 1,333.29 490.75 34,708.56 45,863.72 2033 0.00 0.00 183.02 0.00 1,180.15 394.86 35,103.43 47,043.87 2034 0.00 0.00 162.33 0.00 1,053.53 320.45 35,423.87 48,097.41 2035 0.00 0.00 145.11 0.00 947.28 261.94 35,685.81 49,044.68 2036 0.00 0.00 130.15 0.00 852.44 214.29 35,900.10 49,897.12 938.95 0.00 6,839.99 0.00 0.00 9,190.59 977.04 0.00 56,737.11 36,839.05 56,737.11 Sub-T After Total 0.00 0.00 0.00 8,213.54 0.00 49,897.12 35,900.10 35,900.10 36,839.05 0.00 6,839.99 938.95 49,897.12 Present Worth Profile (M$) PW 5.00% : PW 8.00% : PW 10.00% : PW 12.00% : PW 15.00% : PW 20.00% : 43,989.62 39,293.39 36,839.05 34,768.52 32,196.91 28,895.62 TABLE 2

Proved Producing Rsv Class & Category Year Oil ------ Mbbl Residue Gas ------ MMcf ------ NGL ------- Mbbl ------- Oil ------- Mbbl ------- Gas ----- MMcf----- ------ Net Reserves Volume -------------- Estimated 8/8 Prod. ------- NGL - $/bbl - Oil - $/bbl - Production and Economic Projection As of: 1/1/2022 Wells Res. Gas - $/Mcf - ---------- Plant Net Sales Volume Wet Gas ------ Mbbl ------ 21,516.60 29.67 3,889.85 190,571.33 51.74 25.50 3.20 65.382022 850 4,029.31 13,256.10 18.06 2,448.16 121,520.82 36.51 25.41 3.21 65.352023 849 2,539.79 9,813.26 13.31 1,734.42 88,666.95 27.64 25.39 3.21 65.342024 847 1,802.40 7,768.19 10.52 1,301.94 68,623.73 21.68 25.38 3.21 65.342025 845 1,355.12 6,430.00 8.70 1,022.26 55,476.21 17.54 25.37 3.21 65.332026 842 1,065.53 5,472.32 7.40 827.05 46,125.37 14.52 25.37 3.21 65.342027 840 863.20 4,763.90 6.44 686.34 39,280.52 12.28 25.38 3.21 65.342028 836 717.23 4,188.72 5.66 576.43 33,846.91 10.48 25.38 3.21 65.342029 833 603.07 3,737.62 5.05 492.90 29,646.70 9.09 25.38 3.20 65.342030 830 516.24 3,368.14 4.55 426.63 26,254.92 7.95 25.38 3.20 65.342031 826 447.29 3,066.69 4.14 374.00 23,529.12 7.05 25.39 3.20 65.342032 824 392.49 2,791.08 3.77 328.34 21,112.37 6.25 25.39 3.20 65.352033 821 344.91 2,555.57 3.44 290.92 19,114.15 5.60 25.39 3.20 65.352034 818 305.90 2,344.95 3.15 259.90 17,380.48 5.05 25.39 3.20 65.352035 816 273.48 2,159.48 2.90 232.04 15,821.24 4.57 25.41 3.20 65.352036 811 244.42 21,709.98After 143,766.40 28.42 1,695.15 40.23 Total 243,471.21 2,579,253.73Ult. 114,942.60 940,737.21 155.18 278.18 16,586.32 Cum. Sub-T 25.42 3.20 65.35 25.43 3.18 65.36 93,232.62 796,970.81 126.76 237.95 14,891.17 65.35 25.41 3.21 0.00% Lease Shrinkage and 4.17% Plant Shrinkage 1,638,516.52 128,528.61 17,308.43 1,808.05 15,500.39 Gas ------ M$ ------ Oil ------ M$ ------ Other ------ M$ ------ Year ----------------------------------- Company Future Gross Revenue ---------------------------------- NGL ------ M$ ------ Total ------ M$ ------ Prod Tax ------ M$ ------ Adv Tax ------ M$ ------ after Sev & Adv ------- M$ -------- ------- Prod & Adv Taxes ----- Revenue 1,940.11 1,319.40 12,456.26 0.00 15,715.77 352.75 816.23 14,546.782022 1,180.38 927.92 7,854.69 0.00 9,962.99 222.35 536.61 9,204.032023 869.93 701.73 5,566.91 0.00 7,138.57 161.00 389.05 6,588.512024 687.16 550.26 4,178.71 0.00 5,416.13 123.99 296.08 4,996.062025 568.18 444.98 3,280.13 0.00 4,293.30 99.65 234.34 3,959.312026 483.28 368.39 2,652.77 0.00 3,504.44 82.45 190.62 3,231.372027 420.57 311.66 2,200.53 0.00 2,932.77 69.89 158.83 2,704.052028 369.69 266.06 1,847.48 0.00 2,483.23 59.92 133.80 2,289.502029 329.89 230.59 1,579.11 0.00 2,139.59 52.22 114.68 1,972.682030 297.30 201.91 1,366.23 0.00 1,865.45 45.93 99.46 1,720.062031 270.66 178.86 1,197.23 0.00 1,646.76 40.94 87.35 1,518.482032 246.13 158.76 1,050.56 0.00 1,455.45 36.55 76.78 1,342.132033 224.89 142.25 930.39 0.00 1,297.52 32.90 68.09 1,196.542034 206.04 128.14 831.07 0.00 1,165.25 29.77 60.87 1,074.612035 189.65 116.13 741.94 0.00 1,047.71 27.03 54.50 966.192036 1,857.45 5,397.01After Total 10,141.33 7,070.17 53,131.02 0.00 0.00 1,023.13 Sub-T 70,342.52 8,277.60 1,678.14 240.80 3,714.06 396.76 64,950.32 7,640.04 8,283.87 6,047.05 47,734.01 0.00 62,064.93 1,437.34 3,317.30 57,310.29 Cumulative ------- M$ ------- Annual ------ M$ ------ Disc. Cum. Annual @ 10.00% ------- M$ ------- -------------------- Future Net Income Before Income Taxes ------------------------------------------------------- Deductions Trans. Costs ------ M$ ------ Net Investments ------ M$ ------ Lease Net Costs ------ M$ ------ Net Profits ------ M$ ------ Undiscounted Discounted Ann @ 10.00% -------M$ ------- Year 2022 0.00 0.00 2,116.36 0.00 12,430.43 11,907.55 11,907.55 12,430.43 2023 0.00 0.00 1,335.86 0.00 7,868.17 6,842.95 18,750.50 20,298.59 2024 0.00 0.00 949.52 0.00 5,638.99 4,455.36 23,205.86 25,937.58 2025 0.00 0.00 714.70 0.00 4,281.36 3,073.76 26,279.62 30,218.95 2026 0.00 0.00 561.90 0.00 3,397.40 2,216.97 28,496.59 33,616.35 2027 0.00 0.00 455.04 0.00 2,776.33 1,646.76 30,143.35 36,392.68 2028 0.00 0.00 377.96 0.00 2,326.09 1,254.00 31,397.34 38,718.76 2029 0.00 0.00 317.83 0.00 1,971.67 966.12 32,363.47 40,690.43 2030 0.00 0.00 271.98 0.00 1,700.70 757.56 33,121.03 42,391.13 2031 0.00 0.00 235.58 0.00 1,484.48 601.12 33,722.15 43,875.62 2032 0.00 0.00 206.66 0.00 1,311.81 482.84 34,205.00 45,187.43 2033 0.00 0.00 181.57 0.00 1,160.56 388.31 34,593.30 46,347.99 2034 0.00 0.00 161.00 0.00 1,035.53 314.97 34,908.28 47,383.52 2035 0.00 0.00 143.89 0.00 930.72 257.36 35,165.64 48,314.24 2036 0.00 0.00 129.02 0.00 837.16 210.45 35,376.08 49,151.40 919.42 0.00 6,675.12 0.00 0.00 9,123.80 964.92 0.00 55,826.52 36,295.50 55,826.52 Sub-T After Total 0.00 0.00 0.00 8,158.89 0.00 49,151.40 35,376.08 35,376.08 36,295.50 0.00 6,675.12 919.42 49,151.40 Present Worth Profile (M$) PW 5.00% : PW 8.00% : PW 10.00% : PW 12.00% : PW 15.00% : PW 20.00% : 43,322.96 38,708.46 36,295.50 34,259.32 31,729.80 28,481.95 TABLE 3

Proved Behind Pipe Rsv Class & Category Year Oil ------ Mbbl Residue Gas ------ MMcf ------ NGL ------- Mbbl ------- Oil ------- Mbbl ------- Gas ----- MMcf----- ------ Net Reserves Volume -------------- Estimated 8/8 Prod. ------- NGL - $/bbl - Oil - $/bbl - Production and Economic Projection As of: 1/1/2022 Wells Res. Gas - $/Mcf - ---------- Plant Net Sales Volume Wet Gas ------ Mbbl ------ 1,086.42 2.15 2.20 2,684.92 0.29 34.30 3.03 65.602022 13 3.44 1,467.75 2.34 4.44 5,379.10 0.56 34.47 2.97 65.512023 13 6.88 754.50 1.20 2.97 3,251.21 0.39 34.79 3.00 65.502024 13 4.63 523.11 0.82 2.28 2,405.32 0.30 34.93 3.01 65.502025 13 3.56 405.74 0.63 1.87 1,934.87 0.24 35.01 3.02 65.492026 13 2.92 333.50 0.51 1.58 1,628.00 0.21 35.06 3.02 65.482027 13 2.48 284.99 0.43 1.38 1,413.95 0.18 35.08 3.02 65.482028 13 2.16 248.33 0.37 1.22 1,246.76 0.16 35.10 3.02 65.472029 13 1.91 221.02 0.33 1.10 1,119.60 0.14 35.12 3.02 65.472030 13 1.72 199.43 0.29 1.00 1,017.37 0.13 35.13 3.02 65.472031 13 1.56 182.17 0.27 0.92 934.80 0.12 35.13 3.02 65.462032 13 1.43 166.43 0.24 0.84 857.27 0.11 35.14 3.02 65.462033 13 1.31 152.94 0.22 0.77 789.04 0.10 35.14 3.02 65.462034 13 1.21 140.69 0.21 0.71 726.60 0.09 35.14 3.02 65.462035 13 1.11 129.78 0.19 0.66 671.08 0.09 35.14 3.02 65.462036 13 1.03 1,401.27After 7,375.43 2.04 7.10 0.93 Total 7,720.76 33,557.47Ult. 7,698.08 33,435.31 12.25 4.05 31.04 Cum. Sub-T 34.92 3.01 65.50 35.15 3.02 65.46 6,296.81 26,059.88 10.20 3.12 23.94 65.51 34.85 3.01 0.00% Lease Shrinkage and 35.96% Plant Shrinkage 122.16 22.69 48.47 11.10 37.37 Gas ------ M$ ------ Oil ------ M$ ------ Other ------ M$ ------ Year ----------------------------------- Company Future Gross Revenue ---------------------------------- NGL ------ M$ ------ Total ------ M$ ------ Prod Tax ------ M$ ------ Adv Tax ------ M$ ------ after Sev & Adv ------- M$ -------- ------- Prod & Adv Taxes ----- Revenue 141.02 10.07 6.68 0.00 157.76 7.73 3.77 146.272022 153.05 19.41 13.18 0.00 185.65 9.48 4.45 171.722023 78.79 13.46 8.93 0.00 101.18 5.30 2.42 93.462024 53.79 10.43 6.87 0.00 71.09 3.77 1.70 65.622025 41.13 8.57 5.63 0.00 55.34 2.96 1.32 51.062026 33.40 7.29 4.79 0.00 45.48 2.44 1.09 41.952027 28.24 6.36 4.18 0.00 38.78 2.09 0.93 35.772028 24.38 5.62 3.69 0.00 33.69 1.82 0.80 31.072029 21.52 5.05 3.32 0.00 29.88 1.62 0.71 27.552030 19.27 4.59 3.01 0.00 26.87 1.46 0.64 24.772031 17.50 4.21 2.77 0.00 24.48 1.33 0.58 22.562032 15.93 3.86 2.54 0.00 22.33 1.21 0.53 20.582033 14.62 3.55 2.34 0.00 20.51 1.11 0.49 18.912034 13.45 3.27 2.15 0.00 18.87 1.02 0.45 17.392035 12.41 3.01 1.98 0.00 17.41 0.95 0.42 16.042036 133.81 21.46After Total 802.29 141.29 93.52 0.00 0.00 32.52 Sub-T 1,037.11 187.79 54.48 10.20 24.79 4.49 957.84 173.11 668.49 108.77 72.06 0.00 849.32 44.29 20.30 784.73 Cumulative ------- M$ ------- Annual ------ M$ ------ Disc. Cum. Annual @ 10.00% ------- M$ ------- -------------------- Future Net Income Before Income Taxes ------------------------------------------------------- Deductions Trans. Costs ------ M$ ------ Net Investments ------ M$ ------ Lease Net Costs ------ M$ ------ Net Profits ------ M$ ------ Undiscounted Discounted Ann @ 10.00% -------M$ ------- Year 2022 0.00 0.00 9.61 0.00 136.66 127.04 127.04 136.66 2023 0.00 0.00 11.66 0.00 160.06 139.72 266.77 296.72 2024 0.00 0.00 6.38 0.00 87.08 68.87 335.64 383.80 2025 0.00 0.00 4.48 0.00 61.14 43.91 379.55 444.94 2026 0.00 0.00 3.49 0.00 47.57 31.05 410.59 492.52 2027 0.00 0.00 2.86 0.00 39.08 23.18 433.77 531.60 2028 0.00 0.00 2.44 0.00 33.32 17.96 451.74 564.93 2029 0.00 0.00 2.12 0.00 28.95 14.18 465.92 593.88 2030 0.00 0.00 1.88 0.00 25.68 11.43 477.35 619.55 2031 0.00 0.00 1.69 0.00 23.08 9.35 486.70 642.64 2032 0.00 0.00 1.54 0.00 21.03 7.74 494.44 663.66 2033 0.00 0.00 1.40 0.00 19.18 6.42 500.85 682.85 2034 0.00 0.00 1.29 0.00 17.62 5.36 506.21 700.47 2035 0.00 0.00 1.18 0.00 16.21 4.48 510.69 716.68 2036 0.00 0.00 1.09 0.00 14.95 3.76 514.45 731.63 19.12 0.00 161.36 0.00 0.00 64.84 11.74 0.00 893.00 533.57 893.00 Sub-T After Total 0.00 0.00 0.00 53.09 0.00 731.63 514.45 514.45 533.57 0.00 161.36 19.12 731.63 Present Worth Profile (M$) PW 5.00% : PW 8.00% : PW 10.00% : PW 12.00% : PW 15.00% : PW 20.00% : 654.15 574.11 533.57 499.93 458.69 406.33 TABLE 4

Proved Shut-In Rsv Class & Category Year Oil ------ Mbbl Residue Gas ------ MMcf ------ NGL ------- Mbbl ------- Oil ------- Mbbl ------- Gas ----- MMcf----- ------ Net Reserves Volume -------------- Estimated 8/8 Prod. ------- NGL - $/bbl - Oil - $/bbl - Production and Economic Projection As of: 1/1/2022 Wells Res. Gas - $/Mcf - ---------- Plant Net Sales Volume Wet Gas ------ Mbbl ------ 0.04 0.00 0.00 0.00 0.00 0.00 0.00 65.042022 1 0.00 0.04 0.00 0.00 0.00 0.00 0.00 0.00 65.042023 1 0.00 0.03 0.00 0.00 0.00 0.00 0.00 0.00 65.042024 1 0.00 0.03 0.00 0.00 0.00 0.00 0.00 0.00 65.042025 1 0.00 0.03 0.00 0.00 0.00 0.00 0.00 0.00 65.042026 1 0.00 0.03 0.00 0.00 0.00 0.00 0.00 0.00 65.042027 1 0.00 0.02 0.00 0.00 0.00 0.00 0.00 0.00 65.042028 1 0.00 0.02 0.00 0.00 0.00 0.00 0.00 0.00 65.042029 1 0.00 0.02 0.00 0.00 0.00 0.00 0.00 0.00 65.042030 1 0.00 0.02 0.00 0.00 0.00 0.00 0.00 0.00 65.042031 1 0.00 0.02 0.00 0.00 0.00 0.00 0.00 0.00 65.042032 1 0.00 0.02 0.00 0.00 0.00 0.00 0.00 0.00 65.042033 1 0.00 0.01 0.00 0.00 0.00 0.00 0.00 0.00 65.042034 1 0.00 0.01 0.00 0.00 0.00 0.00 0.00 0.00 65.042035 1 0.00 0.01 0.00 0.00 0.00 0.00 0.00 0.00 65.042036 1 0.00 0.06After 0.00 0.00 0.00 0.00 Total 2,442.55 38,452.00Ult. 0.41 0.00 0.00 0.00 0.00 Cum. Sub-T 0.00 0.00 65.04 0.00 0.00 65.04 0.34 0.00 0.00 0.00 0.00 65.04 0.00 0.00 0.00% Lease Shrinkage and 0.00% Plant Shrinkage 38,452.00 2,442.15 0.00 0.00 0.00 Gas ------ M$ ------ Oil ------ M$ ------ Other ------ M$ ------ Year ----------------------------------- Company Future Gross Revenue ---------------------------------- NGL ------ M$ ------ Total ------ M$ ------ Prod Tax ------ M$ ------ Adv Tax ------ M$ ------ after Sev & Adv ------- M$ -------- ------- Prod & Adv Taxes ----- Revenue 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002022 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002023 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002024 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002025 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002026 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002027 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002028 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002029 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002030 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002031 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002032 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002033 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002034 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002035 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002036 0.00 0.00After Total 0.01 0.00 0.00 0.00 0.00 0.00 Sub-T 0.01 0.00 0.00 0.00 0.00 0.00 0.01 0.00 0.01 0.00 0.00 0.00 0.01 0.00 0.00 0.01 Cumulative ------- M$ ------- Annual ------ M$ ------ Disc. Cum. Annual @ 10.00% ------- M$ ------- -------------------- Future Net Income Before Income Taxes ------------------------------------------------------- Deductions Trans. Costs ------ M$ ------ Net Investments ------ M$ ------ Lease Net Costs ------ M$ ------ Net Profits ------ M$ ------ Undiscounted Discounted Ann @ 10.00% -------M$ ------- Year 2022 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2023 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2024 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2025 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2026 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2027 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2028 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2029 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2030 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2031 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2032 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2033 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2034 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2035 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2036 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.01 0.00 0.01 Sub-T After Total 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Present Worth Profile (M$) PW 5.00% : PW 8.00% : PW 10.00% : PW 12.00% : PW 15.00% : PW 20.00% : 0.00 0.00 0.00 0.00 0.00 0.00 TABLE 5

Proved Undeveloped Rsv Class & Category Year Oil ------ Mbbl Residue Gas ------ MMcf ------ NGL ------- Mbbl ------- Oil ------- Mbbl ------- Gas ----- MMcf----- ------ Net Reserves Volume -------------- Estimated 8/8 Prod. ------- NGL - $/bbl - Oil - $/bbl - Production and Economic Projection As of: 1/1/2022 Wells Res. Gas - $/Mcf - ---------- Plant Net Sales Volume Wet Gas ------ Mbbl ------ 97.68 0.01 0.09 703.35 0.01 31.78 3.58 65.082022 2 0.13 219.62 0.04 0.30 1,843.73 0.02 31.14 3.59 65.062023 2 0.41 114.43 0.02 0.14 887.28 0.01 31.26 3.59 65.062024 2 0.19 81.66 0.02 0.09 599.41 0.01 31.33 3.59 65.062025 2 0.13 64.92 0.01 0.07 458.15 0.00 31.38 3.59 65.062026 2 0.09 54.48 0.01 0.05 372.92 0.00 31.42 3.59 65.062027 2 0.08 47.39 0.01 0.05 316.41 0.00 31.46 3.58 65.062028 2 0.06 41.93 0.01 0.04 274.20 0.00 31.49 3.58 65.062029 2 0.05 37.83 0.01 0.03 242.97 0.00 31.51 3.58 65.062030 2 0.05 34.54 0.01 0.03 218.44 0.00 31.54 3.58 65.062031 2 0.04 31.84 0.01 0.03 198.80 0.00 31.56 3.58 65.062032 2 0.04 29.21 0.01 0.02 181.05 0.00 31.57 3.58 65.062033 2 0.03 26.88 0.00 0.02 166.18 0.00 31.57 3.58 65.062034 2 0.03 24.73 0.00 0.02 152.88 0.00 31.57 3.58 65.062035 2 0.03 22.81 0.00 0.02 141.02 0.00 31.57 3.58 65.062036 2 0.03 247.17After 1,528.20 0.05 0.21 0.02 Total 1,177.13 8,284.99Ult. 1,177.13 8,284.99 0.22 0.09 1.21 Cum. Sub-T 31.40 3.59 65.06 31.57 3.58 65.06 929.96 6,756.80 0.17 0.07 1.00 65.06 31.37 3.59 0.00% Lease Shrinkage and 28.29% Plant Shrinkage 0.00 0.00 1.69 0.29 1.39 Gas ------ M$ ------ Oil ------ M$ ------ Other ------ M$ ------ Year ----------------------------------- Company Future Gross Revenue ---------------------------------- NGL ------ M$ ------ Total ------ M$ ------ Prod Tax ------ M$ ------ Adv Tax ------ M$ ------ after Sev & Adv ------- M$ -------- ------- Prod & Adv Taxes ----- Revenue 0.93 0.21 0.32 0.00 1.46 0.08 0.04 1.342022 2.79 0.66 1.07 0.00 4.52 0.26 0.11 4.152023 1.42 0.30 0.49 0.00 2.21 0.13 0.05 2.032024 1.00 0.20 0.32 0.00 1.53 0.09 0.04 1.402025 0.79 0.15 0.24 0.00 1.19 0.07 0.03 1.092026 0.66 0.12 0.19 0.00 0.98 0.05 0.02 0.902027 0.58 0.10 0.16 0.00 0.84 0.05 0.02 0.772028 0.51 0.09 0.14 0.00 0.74 0.04 0.02 0.682029 0.46 0.08 0.12 0.00 0.66 0.04 0.02 0.602030 0.42 0.07 0.11 0.00 0.60 0.03 0.01 0.552031 0.39 0.06 0.10 0.00 0.55 0.03 0.01 0.502032 0.35 0.06 0.09 0.00 0.50 0.03 0.01 0.462033 0.33 0.05 0.08 0.00 0.46 0.03 0.01 0.422034 0.30 0.05 0.07 0.00 0.42 0.02 0.01 0.392035 0.28 0.04 0.07 0.00 0.39 0.02 0.01 0.362036 2.99 0.75After Total 14.20 2.71 4.33 0.00 0.00 0.48 Sub-T 21.25 4.22 1.18 0.23 0.53 0.10 19.54 3.89 11.20 2.24 3.59 0.00 17.03 0.95 0.42 15.65 Cumulative ------- M$ ------- Annual ------ M$ ------ Disc. Cum. Annual @ 10.00% ------- M$ ------- -------------------- Future Net Income Before Income Taxes ------------------------------------------------------- Deductions Trans. Costs ------ M$ ------ Net Investments ------ M$ ------ Lease Net Costs ------ M$ ------ Net Profits ------ M$ ------ Undiscounted Discounted Ann @ 10.00% -------M$ ------- Year 2022 0.00 0.00 0.14 0.00 1.20 1.10 1.10 1.20 2023 0.00 0.00 0.42 0.00 3.74 3.27 4.37 4.94 2024 0.00 0.00 0.20 0.00 1.83 1.45 5.82 6.77 2025 0.00 0.00 0.14 0.00 1.26 0.91 6.72 8.03 2026 0.00 0.00 0.11 0.00 0.98 0.64 7.36 9.01 2027 0.00 0.00 0.09 0.00 0.81 0.48 7.84 9.82 2028 0.00 0.00 0.08 0.00 0.70 0.38 8.22 10.52 2029 0.00 0.00 0.07 0.00 0.61 0.30 8.52 11.13 2030 0.00 0.00 0.06 0.00 0.54 0.24 8.76 11.67 2031 0.00 0.00 0.05 0.00 0.49 0.20 8.96 12.17 2032 0.00 0.00 0.05 0.00 0.45 0.17 9.13 12.62 2033 0.00 0.00 0.05 0.00 0.41 0.14 9.27 13.03 2034 0.00 0.00 0.04 0.00 0.38 0.12 9.38 13.42 2035 0.00 0.00 0.04 0.00 0.35 0.10 9.48 13.77 2036 0.00 0.00 0.04 0.00 0.32 0.08 9.56 14.09 0.41 0.00 3.50 0.00 0.00 1.94 0.38 0.00 17.59 9.97 17.59 Sub-T After Total 0.00 0.00 0.00 1.56 0.00 14.09 9.56 9.56 9.97 0.00 3.50 0.41 14.09 Present Worth Profile (M$) PW 5.00% : PW 8.00% : PW 10.00% : PW 12.00% : PW 15.00% : PW 20.00% : 12.50 10.82 9.97 9.27 8.42 7.34 TABLE 6

Proved P&A Rsv Class & Category Year Oil ------ Mbbl Residue Gas ------ MMcf ------ NGL ------- Mbbl ------- Oil ------- Mbbl ------- Gas ----- MMcf----- ------ Net Reserves Volume -------------- Estimated 8/8 Prod. ------- NGL - $/bbl - Oil - $/bbl - Production and Economic Projection As of: 1/1/2022 Wells Res. Gas - $/Mcf - ---------- Plant Net Sales Volume Wet Gas ------ Mbbl ------ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002022 0 0.00 0.00After 0.00 0.00 0.00 0.00 Total 63.57 155.52Ult. 0.00 0.00 0.00 0.00 0.00 Cum. Sub-T 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00% Lease Shrinkage and 0.00% Plant Shrinkage 155.52 63.57 0.00 0.00 0.00 Gas ------ M$ ------ Oil ------ M$ ------ Other ------ M$ ------ Year ----------------------------------- Company Future Gross Revenue ---------------------------------- NGL ------ M$ ------ Total ------ M$ ------ Prod Tax ------ M$ ------ Adv Tax ------ M$ ------ after Sev & Adv ------- M$ -------- ------- Prod & Adv Taxes ----- Revenue 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002022 0.00 0.00After Total 0.00 0.00 0.00 0.00 0.00 0.00 Sub-T 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Cumulative ------- M$ ------- Annual ------ M$ ------ Disc. Cum. Annual @ 10.00% ------- M$ ------- -------------------- Future Net Income Before Income Taxes ------------------------------------------------------- Deductions Trans. Costs ------ M$ ------ Net Investments ------ M$ ------ Lease Net Costs ------ M$ ------ Net Profits ------ M$ ------ Undiscounted Discounted Ann @ 10.00% -------M$ ------- Year 2022 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Sub-T After Total 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Present Worth Profile (M$) PW 5.00% : PW 8.00% : PW 10.00% : PW 12.00% : PW 15.00% : PW 20.00% : 0.00 0.00 0.00 0.00 0.00 0.00 TABLE 7

Tabular Summaries

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) Proved Producing Rsv Class & Category 1.99 1.12 0.18 0.02 0.00 1.39 0.64 0.42 0.00P-DP 40.01ABIGAIL 218-219 UNIT 1H - 1H 0.37 0.01 1.36 0.77 0.02 0.02 0.00 1.43 0.05 0.20 0.00P-DP 50.00ACKERLY BROWN 9 1 - 1 0.08 0.00 23.44 16.22 0.00 0.39 0.00 25.09 0.00 1.66 0.00P-DP 20.76ADAMEK UNIT 1H - 1H 0.00 0.00 37.50 21.61 2.15 0.36 0.00 23.50 7.71 4.24 0.00P-DP 50.00ADAMEK UNIT 2H - 2H 10.54 0.45 141.87 72.65 6.62 1.91 0.00 123.42 15.76 17.43 0.00P-DP 42.97ADMIRAL 4-48 47 1H - 1H 20.13 0.62 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00ALEX & PAULINE TAMSULA 1 - 1 0.00 0.00 6.34 4.69 2.50 0.00 0.00 0.00 6.89 0.55 0.00P-DP 7.05ALEX TAMSULA 2 - 2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00ALEX TAMSULA 3 - 3 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00ALEX TAMSULA 4 - 4 0.00 0.00 38.71 24.26 5.03 0.28 0.00 18.35 11.97 6.89 0.00P-DP 30.18ALLMAN 24 1H - 1H 15.29 0.47 8.86 4.66 0.09 0.14 0.00 9.09 0.30 0.91 0.00P-DP 41.96ALLRED UNIT B 08-05 5AH - 5AH 0.38 0.02 4.39 2.42 0.27 0.04 0.00 2.95 0.92 0.63 0.00P-DP 33.89ALLRED UNIT B 08-05 5BH - 5BH 1.16 0.05 9.06 6.11 0.25 0.12 0.00 8.20 0.85 1.06 0.00P-DP 35.97ALLRED UNIT B 08-05 5MH - 5MH 1.07 0.05 9.27 5.68 0.18 0.13 0.00 8.89 0.62 1.03 0.00P-DP 39.45ALLRED UNIT B 08-05 5SH - 5SH 0.79 0.04 16.00 9.85 0.24 0.24 0.00 15.85 0.82 1.71 0.00P-DP 45.34ALLRED UNIT B 08-05 6AH - 6AH 1.03 0.05 12.28 7.24 0.11 0.19 0.00 12.70 0.36 1.23 0.00P-DP 48.22ALLRED UNIT B 08-05 6MH - 6MH 0.45 0.02 11.78 6.80 0.23 0.17 0.00 11.28 0.77 1.24 0.00P-DP 50.00ALLRED UNIT B 08-05 6SH - 6SH 0.96 0.04 9.75 6.17 0.24 0.14 0.00 9.02 0.82 1.12 0.00P-DP 39.10ALLRED UNIT B 08-05 7AH - 7AH 1.03 0.05 8.10 5.03 0.26 0.11 0.00 7.10 0.87 0.97 0.00P-DP 37.50ALLRED UNIT B 08-05 7BH - 7BH 1.10 0.05 9.85 5.39 0.12 0.15 0.00 9.95 0.41 1.03 0.00P-DP 41.85ALLRED UNIT B 08-05 8AH - 8AH 0.52 0.02 7.91 4.70 0.19 0.11 0.00 7.37 0.63 0.90 0.00P-DP 37.42ALLRED UNIT B 08-05 8SH - 8SH 0.80 0.04 1.05 0.77 0.50 0.00 0.00 0.00 1.40 0.36 0.00P-DP 14.77ALPHA 210488 1A - 1A 0.00 0.00 1.52 1.00 0.73 0.00 0.00 0.00 2.05 0.53 0.00P-DP 22.35ALPHA 210488 2B - 2B 0.00 0.00 1.79 1.19 0.85 0.00 0.00 0.00 2.41 0.62 0.00P-DP 23.35ALPHA 210488 3C - 3C 0.00 0.00 193.12 141.49 75.09 0.00 0.00 0.00 250.05 56.93 0.00P-DP 20.02ARCHIE E WYN JF 6H - 6H 0.00 0.00 223.76 142.14 87.00 0.00 0.00 0.00 289.72 65.96 0.00P-DP 27.94ARCHIE E WYN JF 8H - 8H 0.00 0.00 38.43 24.25 23.83 0.00 0.00 0.00 52.91 14.48 0.00P-DP 27.20AUSTIN 5H - 5H 0.00 0.00 38.28 24.23 23.74 0.00 0.00 0.00 52.70 14.42 0.00P-DP 27.07AUSTIN 6H - 6H 0.00 0.00 40.52 25.49 25.13 0.00 0.00 0.00 55.79 15.27 0.00P-DP 27.78AUSTIN 7H - 7H 0.00 0.00 35.27 22.82 21.87 0.00 0.00 0.00 48.56 13.29 0.00P-DP 25.73AUSTIN 8H - 8H 0.00 0.00 8.85 5.11 0.47 0.12 0.00 8.09 1.61 1.97 0.00P-DP 41.27B AND B 1H - 1H 1.12 0.05 10.79 6.20 0.62 0.15 0.00 9.62 2.12 2.42 0.00P-DP 43.96B AND B 2H - 2H 1.47 0.07 8.31 4.71 0.49 0.12 0.00 7.53 1.68 2.07 0.00P-DP 50.00B AND B STATE 4H - 4H 1.16 0.05 9.33 5.43 0.53 0.13 0.00 8.59 1.80 2.30 0.00P-DP 50.00B AND B STATE A 5H - 5H 1.25 0.06 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 0.79 0.38 0.00 0.01 0.00 0.87 0.00 0.08 0.00P-DP 49.41BAKER TRUST 1 - 1 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 50.00BARSTOW -18- 1 - 1 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 50.00BARSTOW -18- 2 - 2 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 50.00BARSTOW -18- 3 - 3 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 50.00BARSTOW -18- 4 - 4 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.00P-DP 50.00BARSTOW -18- 5 - 5 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 50.00BARSTOW -23- 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 20.44BARSTOW -23- 2 - 2 0.00 0.00 0.03 0.02 0.00 0.00 0.00 0.03 0.01 0.01 0.00P-DP 50.00BARSTOW -23- 3 - 3 0.00 0.00 0.01 0.01 0.00 0.00 0.00 0.01 0.00 0.00 0.00P-DP 50.00BARSTOW -23- 4 - 4 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 25.70BARSTOW -23- 6 - 6 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 21.25BARSTOW -23- 6A - 6A 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 33.14BARSTOW -23- 7 - 7 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 31.23BARSTOW -23- 8 - 8 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 50.00BARSTOW -23- 9 - 9 0.00 0.00 0.02 0.01 0.00 0.00 0.00 0.02 0.00 0.00 0.00P-DP 50.00BARSTOW 155 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 26.47BARSTOW 27 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 33.58BARSTOW 27 2 - 2 0.00 0.00 0.07 0.04 0.00 0.00 0.00 0.07 0.00 0.01 0.00P-DP 50.00BARSTOW 27 3 - 3 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 25.75BARSTOW 27 4 - 4 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 50.00BARSTOW 27 5 - 5 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 50.00BARSTOW 27 6 - 6 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 25.24BARSTOW 27 7 - 7 0.00 0.00 0.05 0.03 0.00 0.00 0.00 0.03 0.02 0.01 0.00P-DP 26.21BARSTOW 33 UA 1BS - 1BS 0.01 0.00 0.03 0.02 0.00 0.00 0.00 0.03 0.00 0.01 0.00P-DP 13.88BARSTOW 33 UB 2BS - 2BS 0.00 0.00 0.03 0.01 0.00 0.00 0.00 0.03 0.00 0.00 0.00P-DP 34.36BARSTOW 33-34 1H - 1H 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 4.80BARSTOW 33-35 1H - 1H 0.00 0.00 0.01 0.01 0.00 0.00 0.00 0.01 0.00 0.00 0.00P-DP 31.35BARSTOW 33-35 2H - 2H 0.00 0.00 0.02 0.01 0.00 0.00 0.00 0.01 0.01 0.00 0.00P-DP 29.76BARSTOW 33-35 3H - 3H 0.00 0.00 0.01 0.01 0.00 0.00 0.00 0.01 0.00 0.00 0.00P-DP 50.00BARSTOW A 3652H - 3652H 0.00 0.00 1,065.27 629.35 414.20 0.00 0.00 0.00 1,379.28 314.00 0.00P-DP 35.66BATES S CRC JF 5H - 5H 0.00 0.00 12.70 7.90 0.19 0.20 0.00 13.06 0.58 1.92 0.00P-DP 40.49BIG JAY 10-15 A #1JD 0.97 0.02 14.20 8.79 0.24 0.22 0.00 14.39 0.74 2.15 0.00P-DP 42.44BIG JAY 10-15 A #1LS 1.23 0.03 7.25 4.84 0.07 0.12 0.00 7.74 0.22 1.09 0.00P-DP 32.40BIG JAY 10-15 A #1MS 0.38 0.01 18.57 11.21 0.29 0.29 0.00 18.97 0.90 2.81 0.00P-DP 46.80BIG JAY 10-15 A #1WA 1.51 0.04 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 14.13 9.39 0.23 0.22 0.00 14.37 0.71 2.14 0.00P-DP 39.23BIG JAY 10-15 B #2DN 1.19 0.03 17.44 10.39 0.26 0.27 0.00 17.93 0.80 2.64 0.00P-DP 45.22BIG JAY 10-15 B #2LS 1.34 0.03 13.53 8.19 0.45 0.18 0.00 11.94 1.39 2.12 0.00P-DP 43.12BIG JAY 10-15 B #2WB 2.32 0.06 15.71 10.03 0.18 0.25 0.00 16.55 0.57 2.36 0.00P-DP 42.35BIG JAY 10-15 B #3JC 0.95 0.02 17.32 10.35 0.24 0.27 0.00 17.94 0.74 2.61 0.00P-DP 45.17BIG JAY 10-15 C #4LS 1.25 0.03 5.41 3.71 0.06 0.09 0.00 5.70 0.20 0.81 0.00P-DP 28.46BIG JAY 10-15 C #4MS 0.33 0.01 20.09 12.08 0.52 0.29 0.00 18.84 1.63 3.10 0.00P-DP 47.79BIG JAY 10-15 C #4WA 2.73 0.07 4.20 2.79 0.07 0.06 0.00 4.22 0.23 0.64 0.00P-DP 26.95BIG JAY 10-15 D #5JC 0.39 0.01 5.60 3.90 0.12 0.08 0.00 5.48 0.37 0.86 0.00P-DP 28.51BIG JAY 10-15 D #6DN 0.62 0.02 7.29 4.40 0.16 0.11 0.00 7.08 0.50 1.12 0.00P-DP 36.44BIG JAY 10-15 D #6LS 0.83 0.02 8.41 5.19 0.29 0.11 0.00 7.30 0.91 1.32 0.00P-DP 37.38BIG JAY 10-15 D #6WB 1.52 0.04 6.50 4.30 0.12 0.10 0.00 6.53 0.36 0.99 0.00P-DP 31.85BIG JAY 10-15 E #7JD 0.60 0.02 14.72 8.70 0.23 0.23 0.00 15.05 0.71 2.23 0.00P-DP 43.44BIG JAY 10-15 E #7LS 1.19 0.03 4.69 3.28 0.06 0.07 0.00 4.89 0.19 0.71 0.00P-DP 26.49BIG JAY 10-15 E #7MS 0.32 0.01 12.41 7.61 0.22 0.19 0.00 12.43 0.70 1.89 0.00P-DP 41.84BIG JAY 10-15 E #7WA 1.17 0.03 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00BLACK STONE 34-216 2H - 2H 0.00 0.00 2.17 1.14 0.09 0.03 0.00 2.13 0.30 0.47 0.00P-DP 45.66BOBCAT 55-1-28 UNIT 1H - 1H 0.21 0.01 32.92 17.66 0.49 0.48 0.00 31.47 1.74 2.66 0.00P-DP 28.44BOENING UNIT 1H - 1H 2.38 0.10 31.03 15.65 2.17 0.25 0.00 16.30 7.77 3.67 0.00P-DP 50.00BOENING UNIT 2H - 2H 10.63 0.45 90.02 53.91 2.99 1.12 0.00 72.60 10.71 7.92 0.00P-DP 34.01BOENING UNIT 3H - 3H 14.64 0.62 59.89 37.48 2.65 0.66 0.00 43.09 9.47 5.62 0.00P-DP 50.00BOENING UNIT 4H - 4H 12.95 0.55 89.50 57.29 2.86 1.12 0.00 73.06 10.25 7.84 0.00P-DP 29.63BOENING UNIT 6L - 6L 14.02 0.59 132.06 78.36 3.72 1.72 0.00 111.78 13.33 11.28 0.00P-DP 39.69BOENING UNIT 6U - 6U 18.23 0.77 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00BONACCI 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00BONACCI 2 - 2 0.00 0.00 2.60 1.35 0.06 0.04 0.00 2.57 0.13 0.28 0.00P-DP 36.06BOREAS 79 1H - 1H 0.17 0.01 2.75 1.90 1.07 0.00 0.00 0.00 3.56 0.81 0.00P-DP 23.11BORUM E SMF JF 4H - 4H 0.00 0.00 3.81 2.18 1.48 0.00 0.00 0.00 4.93 1.12 0.00P-DP 34.61BORUM E SMF JF 6H - 6H 0.00 0.00 10.71 6.70 4.17 0.00 0.00 0.00 13.87 3.16 0.00P-DP 29.40BORUM W SMF JF 2H - 2H 0.00 0.00 1.02 0.56 0.03 0.01 0.00 0.95 0.09 0.16 0.00P-DP 40.10BOX NAIL 2LM - 2LM 0.15 0.00 0.62 0.35 0.03 0.01 0.00 0.47 0.09 0.10 0.00P-DP 33.89BOX NAIL 3LL - 3LL 0.15 0.00 0.90 0.49 0.03 0.01 0.00 0.83 0.08 0.14 0.00P-DP 38.85BOX NAIL E 1LM - 1LM 0.13 0.00 8.58 5.94 0.94 0.08 0.00 5.12 3.37 1.87 0.00P-DP 25.03BRACERO 226-34 UNIT 1H - 1H 1.96 0.06 5.50 3.12 0.29 0.08 0.00 4.98 1.03 1.10 0.00P-DP 24.41BRAMBLETT 34-216 1H - 1H 0.60 0.02 18.37 11.47 0.24 0.31 0.00 20.51 0.81 4.53 0.00P-DP 42.88BRAUN B W1 2001MH - 2001MH 1.58 0.06 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 20.26 12.73 0.26 0.34 0.00 22.67 0.88 5.00 0.00P-DP 43.32BRAUN B W3 2001LH - 2001LH 1.71 0.06 18.43 11.06 0.33 0.30 0.00 19.68 1.15 4.63 0.00P-DP 43.66BRAUN C W5 2108LH - 2108LH 2.23 0.08 2.35 1.23 0.24 0.02 0.00 1.51 0.85 0.51 0.00P-DP 50.00BROOKE 184-185 UNIT 2H - 2H 0.50 0.02 0.13 0.07 0.02 0.00 0.00 0.00 0.07 0.03 0.00P-DP 26.82BRUNSON 14 1 - 1 0.09 0.00 2.02 1.04 0.07 0.03 0.00 2.05 0.24 0.43 0.00P-DP 46.39BUCKEYE 55-1-28 UNIT 1H - 1H 0.16 0.01 1,922.14 1,207.74 520.96 0.00 0.00 0.00 1,661.86 672.24 0.00P-DP 38.25BUELL 10-11-5 10H - 10H 932.52 36.74 108.60 71.47 28.22 0.03 0.00 1.51 90.03 38.26 0.00P-DP 21.31BUELL 10-11-5 1H - 1H 55.31 2.18 1,406.25 886.19 369.00 0.03 0.00 1.49 1,177.11 495.51 0.00P-DP 37.23BUELL 10-11-5 206H - 206H 723.15 28.49 1,772.02 1,129.31 480.27 0.00 0.00 0.00 1,532.07 619.74 0.00P-DP 36.85BUELL 10-11-5 210H - 210H 859.69 33.87 98.04 65.84 25.35 0.03 0.00 2.01 80.88 34.53 0.00P-DP 19.77BUELL 10-11-5 2H - 2H 49.69 1.96 98.71 65.86 25.67 0.02 0.00 1.31 81.87 34.77 0.00P-DP 20.08BUELL 10-11-5 3H - 3H 50.30 1.98 125.71 80.68 31.39 0.14 0.00 8.32 100.12 44.24 0.00P-DP 23.52BUELL 10-11-5 4H - 4H 61.51 2.42 795.61 500.21 208.93 0.00 0.00 0.00 666.50 280.35 0.00P-DP 36.61BUELL 10-11-5 6H - 6H 409.46 16.13 0.02 0.01 0.00 0.00 0.00 0.00 0.02 0.01 0.00P-DP 10.94BURKHOLDER A UNIT 1 - 1 0.01 0.00 18.96 11.24 0.78 0.26 0.00 16.99 1.85 2.26 0.00P-DP 40.53BUZZARD NORTH 6972 A 1H - A 1H 2.37 0.07 18.09 11.24 0.80 0.25 0.00 15.93 1.91 2.19 0.00P-DP 39.23BUZZARD NORTH 6972 B 2H - B 2H 2.44 0.07 20.35 12.10 0.89 0.28 0.00 17.97 2.13 2.46 0.00P-DP 41.68BUZZARD NORTH 6972 S 3H - S 3H 2.72 0.08 34.64 20.28 1.81 0.45 0.00 29.24 4.30 4.38 0.00P-DP 46.15Buzzard South 6972 A3H - B 2H 5.49 0.17 23.95 13.44 0.53 0.37 0.00 23.64 1.26 2.55 0.00P-DP 42.40BUZZARD SOUTH 6972 B 1H - B 1H 1.60 0.05 1.64 0.95 0.03 0.03 0.00 1.77 0.11 0.31 0.00P-DP 31.26BYRD 34-170 UNIT 3H - 3H 0.06 0.00 0.24 0.20 0.03 0.00 0.00 0.15 0.10 0.05 0.00P-DP 6.19BYRD 34-170 UNIT 4H - 4H 0.06 0.00 23.34 13.64 2.06 0.26 0.00 16.59 7.41 4.96 0.00P-DP 44.68CALIFORNIA CHROME UNIT 2H - 2H 4.30 0.14 20.68 11.53 1.54 0.25 0.00 16.24 5.53 4.30 0.00P-DP 44.57CALIFORNIA CHROME UNIT 5003HR - 5003HR 3.21 0.10 3.80 2.32 0.00 0.06 0.00 4.15 0.00 0.36 0.00P-DP 16.73CATES 24 1 - 1 0.00 0.00 840.86 560.59 326.94 0.00 0.00 0.00 1,088.71 247.85 0.00P-DP 31.08CENA WYN JF 2H - 2H 0.00 0.00 375.17 274.59 145.87 0.00 0.00 0.00 485.76 110.59 0.00P-DP 19.49CENA WYN JF 4H - 4H 0.00 0.00 64.00 34.84 2.01 1.00 0.00 64.89 7.23 12.33 0.00P-DP 44.34CHALUPA 34-153 UNIT 1H - 1H 4.20 0.14 93.40 54.28 1.69 1.56 0.00 101.31 6.10 17.56 0.00P-DP 46.39CHALUPA 34-153 UNIT 2H - 2H 3.54 0.12 29.23 17.63 0.51 0.43 0.00 28.50 1.73 3.18 0.00P-DP 44.39CHAPARRAL UNIT A1 15SH 2.17 0.10 37.86 22.68 0.55 0.57 0.00 37.70 1.85 4.02 0.00P-DP 47.51CHAPARRAL UNIT A1 21H 2.33 0.11 44.57 26.68 0.97 0.64 0.00 42.12 3.29 5.00 0.00P-DP 49.42CHAPARRAL UNIT A1 8AH 4.15 0.19 8.67 2.98 2.60 0.00 0.00 0.00 8.67 0.00 0.00P-DP 50.00CHARLES ADAMCHICK 4 - 4 0.00 0.00 6.15 2.59 2.01 0.00 0.00 0.00 6.69 0.54 0.00P-DP 34.17CHARLES ADAMCHICK 5 - 5 0.00 0.00 4.89 2.34 1.47 0.00 0.00 0.00 4.89 0.00 0.00P-DP 44.77CHARLES ADAMCHICK 7 - 7 0.00 0.00 28.59 18.10 13.63 0.00 0.00 0.00 38.44 9.85 0.00P-DP 36.47CHARLIE 210468 7A - 7A 0.00 0.00 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 23.84 15.35 11.37 0.00 0.00 0.00 32.05 8.21 0.00P-DP 34.05CHARLIE 210468 8B - 8B 0.00 0.00 317.02 207.64 151.14 0.00 0.00 0.00 426.20 109.18 0.00P-DP 37.20CHARLIE 210469 10B - 10B 0.00 0.00 336.70 218.36 160.52 0.00 0.00 0.00 452.65 115.96 0.00P-DP 38.15CHARLIE 210469 9A - 9A 0.00 0.00 83.42 60.61 39.77 0.00 0.00 0.00 112.16 28.73 0.00P-DP 13.27CHARLIE 210472 4A - 4A 0.00 0.00 154.26 98.61 73.54 0.00 0.00 0.00 207.39 53.13 0.00P-DP 21.86CHARLIE 210472 5B - 5B 0.00 0.00 110.64 78.96 52.75 0.00 0.00 0.00 148.75 38.10 0.00P-DP 15.24CHARLIE 210472 6C - 6C 0.00 0.00 4.85 2.75 0.14 0.08 0.00 4.99 0.50 0.93 0.00P-DP 44.92CHILI PEPPER 34-137 UNIT 1H - 1H 0.29 0.01 2.23 1.16 0.11 0.03 0.00 2.10 0.37 0.49 0.00P-DP 42.57CHINOOK 55-1-7 UNIT 1H - 1H 0.26 0.01 1.76 0.92 0.16 0.01 0.00 0.65 0.57 0.24 0.00P-DP 33.27CHUMCHAL UNIT 1H - 1H 0.78 0.03 0.98 0.77 0.10 0.00 0.00 0.27 0.35 0.13 0.00P-DP 6.62CHUMCHAL UNIT 2H - 2H 0.48 0.02 1.81 0.96 0.09 0.02 0.00 1.25 0.32 0.19 0.00P-DP 24.34CHUMCHAL UNIT 3H - 3H 0.43 0.02 16.94 9.16 0.35 0.24 0.00 15.38 1.27 1.44 0.00P-DP 22.17CHUMCHAL UNIT 4H - 4H 1.73 0.07 71.45 42.84 2.87 0.83 0.00 53.71 10.26 6.54 0.00P-DP 38.37CHUMCHAL UNIT 6L - 6L 14.02 0.59 60.72 40.07 1.91 0.77 0.00 49.88 6.82 5.30 0.00P-DP 27.74CHUMCHAL UNIT 7L - 7L 9.33 0.40 5.50 3.12 0.11 0.09 0.00 5.91 0.39 1.04 0.00P-DP 49.19CHURRO 34-157/158 UNIT 1H - 1H 0.23 0.01 0.61 0.37 0.00 0.01 0.00 0.65 0.01 0.06 0.00P-DP 28.30COLE 36-37 A UNIT A 2H - A 2H 0.01 0.00 90.77 44.26 3.48 1.08 0.00 70.08 12.44 8.76 0.00P-DP 50.00COLLE UNIT 1H - 1H 17.01 0.72 553.43 385.43 215.18 0.00 0.00 0.00 716.56 163.13 0.00P-DP 21.34COLLINS WYN JF 2H - 2H 0.00 0.00 701.93 465.74 272.92 0.00 0.00 0.00 908.83 206.90 0.00P-DP 25.34COLLINS WYN JF 4H - 4H 0.00 0.00 744.46 490.77 289.46 0.00 0.00 0.00 963.90 219.44 0.00P-DP 26.12COLLINS WYN JF 6H - 6H 0.00 0.00 0.09 0.05 0.00 0.00 0.00 0.10 0.01 0.02 0.00P-DP 22.25COLUMBINE 34-167 1H - 1H 0.00 0.00 0.22 0.12 0.00 0.00 0.00 0.24 0.02 0.04 0.00P-DP 31.04COLUMBINE 34-167 2H - 2H 0.01 0.00 0.02 0.02 0.00 0.00 0.00 0.02 0.01 0.00 0.00P-DP 9.44COLUMBINE 34-167 3H - 3H 0.00 0.00 0.21 0.11 0.01 0.00 0.00 0.21 0.02 0.04 0.00P-DP 31.02COLUMBINE 34-167 4H - 4H 0.01 0.00 0.21 0.10 0.01 0.00 0.00 0.18 0.04 0.04 0.00P-DP 50.00CONSTANTAN 34-174 (N) 1H - 1H 0.02 0.00 3.20 1.88 0.27 0.04 0.00 2.35 0.96 0.68 0.00P-DP 36.70CORNELL 226-34 1H - 1H 0.56 0.02 2.02 1.02 0.04 0.03 0.00 2.19 0.14 0.39 0.00P-DP 50.00CRAZY CAMEL 1 - 1 0.08 0.00 732.34 445.29 284.74 0.00 0.00 0.00 948.20 215.87 0.00P-DP 27.13CROSS CREEK A 5H-20 - 5H-20 0.00 0.00 9.87 4.85 0.27 0.16 0.00 10.22 0.97 1.89 0.00P-DP 50.00CROSS V RANCH 34-170 UNIT 1H - 1H 0.57 0.02 24.40 15.70 11.63 0.00 0.00 0.00 32.80 8.40 0.00P-DP 34.28CROWIE E RCH BL 3H - 3H 0.00 0.00 18.29 10.62 8.72 0.00 0.00 0.00 24.59 6.30 0.00P-DP 34.63CROWIE RCH BL 1H - 1H 0.00 0.00 3.11 1.89 1.18 0.00 0.00 0.02 3.75 0.66 0.00P-DP 22.69CV RA SU127;PACE ETAL 8-17 HC 001 - 001 0.00 0.00 2.15 1.13 0.82 0.00 0.00 0.00 2.60 0.46 0.00P-DP 21.82CV RA SU91;EDGAR S TALBERT 9 H 001 - 001 0.00 0.00 0.83 0.67 0.31 0.00 0.00 0.00 0.93 0.11 0.00P-DP 5.07CV RB SU58;SJ MONDELLO ETAL 18 001 - 001 0.00 0.00 2.11 1.43 0.82 0.00 0.00 0.00 2.60 0.49 0.00P-DP 9.90CV RB SUV;SHELBY INTERESTS 31 001 - 001 0.00 0.00 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 46.01 24.58 17.89 0.00 0.00 0.00 56.71 10.70 0.00P-DP 22.63CV RB SUW;LESHE 36 001 - 001 0.00 0.00 21.55 12.87 8.38 0.00 0.00 0.00 26.56 5.01 0.00P-DP 15.22CV RB SUW;NAC 36 001-ALT - 001-ALT 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00DANIEL D & EDNA MILLER 1 - 1 0.00 0.00 3.56 1.98 0.21 0.05 0.00 3.11 0.74 0.72 0.00P-DP 45.57DANIELLE 183 UNIT 1H - 1H 0.43 0.01 3.79 2.07 0.27 0.05 0.00 3.07 0.96 0.78 0.00P-DP 46.96DANIELLE 183 UNIT 2H - 2H 0.55 0.02 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00DAVID L BONACCI 0031 - 0031 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00DAVIS 1 - 1 0.00 0.00 5.03 3.13 0.50 0.05 0.00 3.27 1.80 1.09 0.00P-DP 37.65DAVIS 201-200-199 UNIT 1H - 1H 1.05 0.03 0.43 0.22 0.05 0.00 0.00 0.26 0.16 0.09 0.00P-DP 50.00DEVILS CASTLE 1H - 1H 0.10 0.00 1,205.19 769.03 468.60 0.00 0.00 0.00 1,560.43 355.24 0.00P-DP 30.23DICKSON CRC JF 1H - 1H 0.00 0.00 1,185.86 747.82 461.08 0.00 0.00 0.00 1,535.41 349.55 0.00P-DP 30.48DICKSON CRC JF 3H - 3H 0.00 0.00 0.08 0.06 0.04 0.00 0.00 0.00 0.11 0.03 0.00P-DP 21.60DILLES BOTTOM 210744 3B - 3B 0.00 0.00 15.88 8.68 2.92 0.05 0.00 3.43 6.96 3.40 0.00P-DP 27.92DONALDSON 4-54 1H - 1H 8.89 0.27 2.46 1.35 0.33 0.02 0.00 1.12 0.78 0.44 0.00P-DP 35.66DONALDSON 4-54 U 34H - U 34H 1.00 0.03 214.75 156.02 127.69 0.00 0.00 0.00 425.19 210.44 0.00P-DP 50.00DOYEN NE WEL JF 3H - 3H 0.00 0.00 4.51 3.01 2.68 0.00 0.00 0.00 8.93 4.42 0.00P-DP 50.00DOYEN NW WEL JF 1H - 1H 0.00 0.00 2.59 1.36 0.03 0.04 0.00 2.89 0.12 0.48 0.00P-DP 31.97DRAINAGE 34-136 1H - 1H 0.07 0.00 1.56 0.81 0.05 0.02 0.00 1.58 0.18 0.30 0.00P-DP 27.44DRAINAGE 34-136 2H - 2H 0.10 0.00 1.23 0.79 0.01 0.02 0.00 1.40 0.04 0.23 0.00P-DP 19.29DRAINAGE 34-136 3H - 3H 0.02 0.00 2.69 1.45 0.01 0.05 0.00 3.12 0.03 0.49 0.00P-DP 31.77DRAINAGE 34-136 4H - 4H 0.02 0.00 2.89 1.61 0.13 0.04 0.00 2.73 0.46 0.57 0.00P-DP 34.52EILAND 1806A-33 1H - 1H 0.27 0.01 6.08 3.24 0.07 0.10 0.00 6.80 0.26 1.13 0.00P-DP 43.75EILAND 1806B-33 1H - 1H 0.15 0.00 4.14 2.33 0.06 0.07 0.00 4.56 0.22 0.77 0.00P-DP 38.64EILAND 1806B-33 62H - 62H 0.13 0.00 1.42 0.87 0.04 0.02 0.00 1.48 0.13 0.27 0.00P-DP 25.64EILAND 1806C-33 1H - 1H 0.08 0.00 4.93 2.98 0.11 0.08 0.00 5.21 0.41 0.94 0.00P-DP 38.70EILAND 1806C-33 83H - 83H 0.24 0.01 27.06 16.71 0.61 0.44 0.00 28.69 2.21 5.13 0.00P-DP 34.07EILAND 6047A-34 41H - 41H 1.28 0.04 3.55 2.20 0.04 0.06 0.00 3.54 0.14 0.33 0.00P-DP 35.49EL KABONG UNIT 48-17-8 301H - 301H 0.21 0.01 4.20 2.88 0.04 0.07 0.00 4.22 0.15 0.39 0.00P-DP 33.09EL KABONG UNIT 48-17-8 302H - 302H 0.22 0.01 3.42 2.03 0.03 0.06 0.00 3.48 0.10 0.31 0.00P-DP 35.67EL KABONG UNIT 48-17-8 701H - 701H 0.15 0.01 7.20 4.12 0.07 0.12 0.00 7.23 0.26 0.67 0.00P-DP 45.22EL KABONG UNIT 48-17-8 702H - 702H 0.38 0.01 5.15 2.86 0.06 0.08 0.00 5.06 0.24 0.49 0.00P-DP 42.10EL KABONG UNIT 48-17-8 703H - 703H 0.35 0.01 3.10 1.95 0.03 0.05 0.00 3.07 0.13 0.29 0.00P-DP 32.94EL KABONG UNIT 48-17-8 704H - 704H 0.19 0.01 0.61 0.49 0.01 0.01 0.00 0.56 0.05 0.06 0.00P-DP 11.59EL KABONG UNIT 48-17-8 801H - 801H 0.07 0.00 13.58 7.57 0.82 0.17 0.00 10.94 1.94 1.79 0.00P-DP 46.37ELKHEAD 4144 A 2H - A 2H 2.48 0.08 14.70 7.81 1.13 0.16 0.00 10.65 2.70 2.10 0.00P-DP 48.70ELKHEAD 4144 A 5H - A 5H 3.45 0.11 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 12.28 7.16 0.85 0.14 0.00 9.35 2.03 1.69 0.00P-DP 44.48ELKHEAD 4144 A 7H - A 7H 2.59 0.08 8.70 4.79 0.43 0.12 0.00 7.45 1.03 1.09 0.00P-DP 43.05ELKHEAD 4144 B 1H - B 1H 1.32 0.04 5.65 3.29 0.41 0.07 0.00 4.24 0.97 0.79 0.00P-DP 36.04ELKHEAD 4144 B 6H - B 6H 1.23 0.04 11.36 6.32 0.76 0.14 0.00 8.80 1.80 1.55 0.00P-DP 44.77ELKHEAD 4144 B 8H - B 8H 2.31 0.07 7.75 4.53 0.58 0.09 0.00 5.68 1.39 1.10 0.00P-DP 39.25ELKHEAD 4144 C 4H - C 4H 1.78 0.05 12.71 6.74 0.70 0.16 0.00 10.57 1.66 1.63 0.00P-DP 47.08ELKHEAD 4144 S 3H - S 3H 2.12 0.07 0.28 0.15 0.01 0.00 0.00 0.29 0.03 0.05 0.00P-DP 41.31ELUSIVE JAZZ 167-168 2HA - 2HA 0.02 0.00 4.31 2.38 1.51 0.00 0.00 0.00 5.63 1.32 0.00P-DP 22.95ELY GAS UNIT NO. 2 1 - 1 0.00 0.00 3.41 1.89 0.32 0.04 0.00 2.33 1.15 0.73 0.00P-DP 46.52EMMA 218-219 UNIT 1H - 1H 0.67 0.02 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00EUGENE L CONDOR NT243 - NT243 0.00 0.00 40.74 23.61 1.52 0.55 0.00 36.00 5.14 3.94 0.00P-DP 22.64FAIREY UNIT 1H - 1H 3.53 0.16 48.38 23.79 1.79 0.58 0.00 37.85 6.42 4.68 0.00P-DP 50.00FIELDS UNIT 1H - 1H 8.78 0.37 27.66 14.06 1.12 0.32 0.00 20.89 4.01 2.73 0.00P-DP 48.99FIELDS UNIT 2H - 2H 5.49 0.23 29.23 18.35 0.98 0.36 0.00 23.69 3.50 2.73 0.00P-DP 16.74FIELDS UNIT 3H - 3H 4.78 0.20 22.20 10.39 1.69 0.16 0.00 10.62 6.05 2.75 0.00P-DP 50.00FIELDS UNIT 4H - 4H 8.28 0.35 1.42 0.70 0.06 0.02 0.00 1.38 0.20 0.28 0.00P-DP 33.23FINLEY 1-11 WRD 1H - 1H 0.12 0.00 1.48 0.75 0.01 0.03 0.00 1.72 0.02 0.27 0.00P-DP 32.46FINLEY 1-11 WRD 2H - 2H 0.01 0.00 19.23 11.16 0.68 0.29 0.00 19.07 2.47 3.73 0.00P-DP 44.70Fire Frog 1 ** 1.43 0.05 23.19 13.36 1.84 0.33 0.00 21.56 6.64 5.11 0.00P-DP 48.67Fire Frog 2 ** 0.09 0.00 27.87 16.62 1.31 0.44 0.00 28.79 4.71 5.69 0.00P-DP 49.98Fire Frog 3 ** 0.07 0.00 27.59 16.46 1.41 0.43 0.00 28.14 5.07 5.69 0.00P-DP 49.87Fire Frog 4 ** 0.07 0.00 0.05 0.03 0.00 0.00 0.00 0.03 0.02 0.01 0.00P-DP 18.77FIREBIRD 52 1 - 1 0.01 0.00 5.27 2.67 0.01 0.08 0.00 5.54 0.02 0.32 0.00P-DP 29.39FISHERMAN -A- 1 - 1 0.03 0.00 4.73 2.22 0.05 0.08 0.00 4.94 0.17 0.66 0.00P-DP 50.00FISHERMAN -A- 2 - 2 0.29 0.01 41.19 25.01 0.33 0.68 0.00 44.58 1.03 6.14 0.00P-DP 35.98FISHERMAN-BRISTOW 23A 1H - 1H 1.72 0.04 95.24 55.30 1.04 1.54 0.00 100.89 3.23 14.29 0.00P-DP 45.74FISHERMAN-BRISTOW 23B 2H - 2H 5.41 0.14 72.90 43.01 0.98 1.16 0.00 75.77 3.04 10.99 0.00P-DP 42.60FISHERMAN-BRISTOW 23C 3H - 3H 5.08 0.13 109.48 63.66 1.10 1.78 0.00 116.71 3.43 16.40 0.00P-DP 47.33FISHERMAN-BRISTOW 23D 4H - 4H 5.74 0.14 42.10 23.06 6.97 0.20 0.00 12.82 16.59 8.50 0.00P-DP 27.79FLEMING 13 10H - 10H 21.19 0.65 0.04 0.02 0.00 0.00 0.00 0.04 0.01 0.01 0.00P-DP 50.00FUNKY BOSS B 8251H - 8251H 0.00 0.00 0.02 0.01 0.00 0.00 0.00 0.02 0.01 0.00 0.00P-DP 46.95FUNKY BOSS C 8270H - 8270H 0.00 0.00 0.45 0.27 0.01 0.01 0.00 0.46 0.05 0.09 0.00P-DP 35.30GADDIE 1-31 UNIT 1H - 1H 0.03 0.00 0.24 0.13 0.01 0.00 0.00 0.25 0.02 0.05 0.00P-DP 32.50GADDIE 1-31 UNIT 2H - 2H 0.01 0.00 0.12 0.09 0.00 0.00 0.00 0.13 0.01 0.02 0.00P-DP 17.91GADDIE 1-31 UNIT 3H - 3H 0.00 0.00 151.94 95.89 60.06 0.00 0.00 0.00 165.15 13.21 0.00P-DP 14.76GENFIVE ENERGY LLC UNIT 0.00 0.00 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 16.52 10.78 2.19 0.12 0.00 7.64 5.20 2.97 0.00P-DP 21.69GEORGE T STAGG 5-2 UNIT 1H - 1H 6.64 0.20 18.55 8.65 0.58 0.24 0.00 15.33 2.09 1.73 0.00P-DP 50.00GERDES UNIT 1H - 1H 2.86 0.12 47.28 25.74 2.67 0.46 0.00 29.84 9.56 5.18 0.00P-DP 22.89GERDES UNIT 2H - 2H 13.07 0.55 29.71 15.31 0.89 0.38 0.00 24.91 3.17 2.71 0.00P-DP 50.00GERDES UNIT 3H - 3H 4.34 0.18 50.69 27.25 1.52 0.65 0.00 42.38 5.46 4.61 0.00P-DP 26.52GERDES UNIT 4H - 4H 7.46 0.32 79.13 50.41 2.10 1.05 0.00 68.05 7.51 6.70 0.00P-DP 26.57GERDES UNIT 5H - 5H 10.26 0.44 91.44 55.50 2.53 1.20 0.00 77.80 9.05 7.79 0.00P-DP 29.61GERDES UNIT 6H - 6H 12.37 0.52 149.87 85.54 4.28 1.94 0.00 126.42 15.32 12.81 0.00P-DP 38.47GERDES-LANGHOFF 1L - 1L 20.94 0.89 149.86 84.69 4.06 1.97 0.00 128.18 14.52 12.70 0.00P-DP 40.45GERDES-RATHKAMP 1L - 1L 19.85 0.84 45.30 25.09 0.13 0.72 0.00 47.85 0.44 3.29 0.00P-DP 30.70GILLESPIE UNIT 1H - 1H 0.30 0.01 0.14 0.10 0.01 0.00 0.00 0.05 0.04 0.02 0.00P-DP 8.40GLASS RANCH 19 2HA - 2HA 0.07 0.00 441.79 300.66 171.78 0.00 0.00 0.00 572.02 130.22 0.00P-DP 22.82GORDON SE CRC JF 4H - 4H 0.00 0.00 729.03 452.04 283.46 0.00 0.00 0.00 943.93 214.89 0.00P-DP 30.88GORDON SE CRC JF 6H - 6H 0.00 0.00 393.86 281.47 153.14 0.00 0.00 0.00 509.96 116.10 0.00P-DP 18.70GORDON SW CRC JF 2H - 2H 0.00 0.00 17.62 10.28 0.50 0.24 0.00 15.83 1.70 2.07 0.00P-DP 41.68GRANT 18A 4HK - 4HK 2.15 0.10 11.39 7.20 0.24 0.16 0.00 10.82 0.82 1.27 0.00P-DP 39.71GRANT 18B 5HJ - 5HJ 1.03 0.05 6.29 3.90 0.25 0.08 0.00 5.18 0.84 0.79 0.00P-DP 33.76GRANT 18B 6HK - 6HK 1.06 0.05 267.97 188.75 104.19 0.00 0.00 0.00 346.96 78.99 0.00P-DP 23.53GRISWOLD S WYN JF 4H - 4H 0.00 0.00 71.40 48.87 27.76 0.00 0.00 0.00 92.45 21.05 0.00P-DP 25.05GRISWOLD SW WYN JF 2H - 2H 0.00 0.00 321.08 239.76 124.84 0.00 0.00 0.00 415.72 94.64 0.00P-DP 16.61GRISWOLD WYN JF 6H - 6H 0.00 0.00 584.61 406.42 227.31 0.00 0.00 0.00 756.93 172.32 0.00P-DP 24.57GRISWOLD WYN JF 8H - 8H 0.00 0.00 10.92 5.68 0.50 0.15 0.00 9.57 1.18 1.33 0.00P-DP 43.17GRIZZLY BEAR 7780 2U A 2H - A 2H 1.51 0.05 6.25 3.33 0.58 0.06 0.00 4.05 1.38 0.96 0.00P-DP 36.02GRIZZLY BEAR 7780 3U A 3H - A 3H 1.77 0.05 12.76 6.71 0.71 0.16 0.00 10.56 1.69 1.64 0.00P-DP 45.08GRIZZLY BEAR 7780 4U A 4H - A 4H 2.16 0.07 1.52 0.98 0.15 0.01 0.00 0.96 0.35 0.24 0.00P-DP 18.47GRIZZLY BEAR 7780 5U A 5H - A 5H 0.45 0.01 13.53 7.00 0.93 0.16 0.00 10.35 2.21 1.86 0.00P-DP 46.62GRIZZLY BEAR 7780 6U A 6H - A 6H 2.82 0.09 18.29 10.53 0.52 0.27 0.00 17.40 1.23 1.90 0.00P-DP 50.00GRIZZLY SOUTH 7673 A 1H - A 1H 1.57 0.05 18.89 11.93 0.69 0.27 0.00 17.37 1.63 2.19 0.00P-DP 31.61GRIZZLY SOUTH 7673 A 3H - A 3H 2.09 0.06 55.86 33.57 1.75 0.82 0.00 52.67 4.16 6.29 0.00P-DP 44.64GRIZZLY SOUTH 7673 A 5H - A 5H 5.32 0.16 37.93 23.23 1.19 0.55 0.00 35.76 2.83 4.27 0.00P-DP 39.83GRIZZLY SOUTH 7673 A 8H - A 8H 3.61 0.11 16.67 10.95 0.95 0.21 0.00 13.67 2.26 2.16 0.00P-DP 28.47GRIZZLY SOUTH 7673 B 2H - B 2H 2.89 0.09 18.44 10.70 0.70 0.26 0.00 16.82 1.66 2.16 0.00P-DP 33.34GRIZZLY SOUTH 7673 B 4H - B 4H 2.12 0.07 63.48 40.33 2.63 0.88 0.00 56.80 6.26 7.58 0.00P-DP 44.80GRIZZLY SOUTH 7673 B 6H - B 6H 8.00 0.25 16.47 8.21 0.83 0.22 0.00 14.04 1.97 2.06 0.00P-DP 43.85GRIZZLY WEST 77 1H - 1H 2.52 0.08 8.17 4.36 0.32 0.11 0.00 7.41 0.76 0.96 0.00P-DP 34.01GRIZZLY WEST 77 A 3H - A 3H 0.97 0.03 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 5.73 3.22 0.20 0.08 0.00 5.28 0.49 0.66 0.00P-DP 29.21GRIZZLY WEST 77 C 2H - C 2H 0.62 0.02 1.23 0.61 0.04 0.02 0.00 1.03 0.15 0.14 0.00P-DP 50.00GUITAR 11 1 - 1 0.19 0.01 3.17 1.55 0.07 0.04 0.00 2.96 0.25 0.34 0.00P-DP 48.11GUITAR 13 1 - 1 0.31 0.01 3.45 1.80 0.02 0.05 0.00 3.62 0.08 0.34 0.00P-DP 39.10GUNSLINGER UNIT L 4H - L 4H 0.10 0.00 36.67 23.13 0.63 0.56 0.00 36.98 1.97 5.57 0.00P-DP 41.08GUNSMOKE 1-40 (ALLOC 1-NH) 4LB ** 3.29 0.08 81.76 49.71 1.15 1.29 0.00 84.50 3.59 12.34 0.00P-DP 50.00GUNSMOKE 1-40 (ALLOC-2NH) 3LA ** 6.01 0.15 2.49 1.59 0.02 0.04 0.00 2.86 0.08 0.61 0.00P-DP 25.08GUY COWDEN UNIT 2 2505BH - 2505BH 0.16 0.01 8.23 4.67 0.69 0.06 0.00 3.79 2.36 2.52 0.00P-DP 36.97GUY COWDEN UNIT 2 2506BH - 2506BH 4.60 0.16 0.64 0.39 0.03 0.01 0.00 0.46 0.12 0.18 0.00P-DP 16.06GUY COWDEN UNIT 2 2507BH - 2507BH 0.23 0.01 10.24 5.44 0.64 0.10 0.00 6.68 2.21 2.96 0.00P-DP 43.90GUY COWDEN UNIT 2 2508BH - 2508BH 4.30 0.15 3.96 2.43 0.45 0.01 0.00 0.71 1.55 1.31 0.00P-DP 29.23GUY COWDEN UNIT 2 2515AH - 2515AH 3.02 0.11 8.20 4.71 0.28 0.11 0.00 7.54 0.96 2.17 0.00P-DP 36.49GUY COWDEN UNIT 2 2516AH - 2516AH 1.88 0.07 5.87 3.25 0.43 0.05 0.00 3.29 1.47 1.74 0.00P-DP 32.61GUY COWDEN UNIT 2 2517AH - 2517AH 2.85 0.10 8.32 4.80 0.21 0.13 0.00 8.37 0.71 2.14 0.00P-DP 40.29GUY COWDEN UNIT 2 2518AH - 2518AH 1.38 0.05 106.70 78.59 41.48 0.00 0.00 0.00 131.50 24.81 0.00P-DP 28.04HA RA SU77;LEE 25-36 HC 001-ALT - 001-ALT 0.00 0.00 1.95 1.09 0.75 0.00 0.00 0.00 2.36 0.42 0.00P-DP 20.07HA RA SU98;PACE 8-14-16 H 001 - 001 0.00 0.00 840.46 525.92 304.29 0.00 0.00 0.00 943.31 102.85 0.00P-DP 50.00HA RA SUA;GOLSON 36-25 HC 001-ALT - 001-ALT 0.00 0.00 844.99 529.65 305.93 0.00 0.00 0.00 948.40 103.41 0.00P-DP 50.00HA RA SUA;GOLSON 36-25 HC 002-ALT - 002-ALT 0.00 0.00 1,848.98 1,528.10 718.89 0.00 0.00 0.00 2,278.87 429.89 0.00P-DP 50.00HA RA SUA;NAC 36 H 001-ALT (3 Wells) - 001-ALT 0.00 0.00 661.16 390.05 250.25 0.00 0.00 0.00 745.75 84.58 0.00P-DP 39.36HA RA SUA;WIGGINS 36-25 HC 001 - 001 0.00 0.00 587.50 346.53 222.37 0.00 0.00 0.00 662.66 75.16 0.00P-DP 37.51HA RA SUA;WIGGINS 36-25 HC 002-ALT - 002-ALT 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00HA RA SUB;SHELBY INTERESTS 31H 001 - 001 0.00 0.00 1.02 0.84 0.40 0.00 0.00 0.00 1.25 0.22 0.00P-DP 5.03HA RA SUCC;BAKER 7-11-14 H 001 - 001 0.00 0.00 11.86 8.39 4.49 0.00 0.00 0.00 13.37 1.52 0.00P-DP 22.20HA RA SUL;L & L INV 18-19 HC 001-ALT - 001-ALT 0.00 0.00 8.50 6.51 3.22 0.00 0.00 0.00 9.58 1.09 0.00P-DP 15.66HA RA SUL;L & L INV 18-19 HC 002-ALT - 002-ALT 0.00 0.00 2.95 2.48 1.12 0.00 0.00 0.00 3.32 0.38 0.00P-DP 3.98HA RA SUL;MADDEN 18 H 001 - 001 0.00 0.00 69.19 50.86 26.19 0.00 0.00 0.00 78.04 8.85 0.00P-DP 16.57HA RA SUL;MADDEN 18 H 002-ALT - 002-ALT 0.00 0.00 8.56 6.05 3.24 0.00 0.00 0.00 9.65 1.09 0.00P-DP 18.22HA RA SUL;MADDEN 18-19 HC 001-ALT - 001-ALT 0.00 0.00 2.88 1.48 1.10 0.00 0.00 0.00 3.50 0.62 0.00P-DP 24.73HA RA SUL;TALBERT 9-14-16 H 001 - 001 0.00 0.00 431.80 222.38 163.44 0.00 0.00 0.00 487.05 55.24 0.00P-DP 28.37HA RA SUS;POOLE-DRAKE 21 H 001 - 001 0.00 0.00 0.20 0.17 0.08 0.00 0.00 0.00 0.24 0.04 0.00P-DP 5.02HA RA SUSS;JORDAN 16-21 HC 001-ALT - 001-ALT 0.00 0.00 0.30 0.23 0.12 0.00 0.00 0.00 0.36 0.07 0.00P-DP 6.42HA RA SUTT;BSMC LA 21 HZ 001 - 001 0.00 0.00 18.92 10.46 7.16 0.00 0.00 0.00 21.34 2.42 0.00P-DP 21.82HA RA SUZ;GLOVER 20 001 - 001 0.00 0.00 37.00 17.24 14.00 0.00 0.00 0.00 41.73 4.73 0.00P-DP 33.41HA RA SUZ;GLOVER 20 002-ALT - 002-ALT 0.00 0.00 28.86 16.33 10.93 0.00 0.00 0.00 32.56 3.69 0.00P-DP 24.61HA RA SUZ;GLOVER 20 003-ALT - 003-ALT 0.00 0.00 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 9.56 6.15 3.62 0.00 0.00 0.00 10.78 1.22 0.00P-DP 14.00HA RA SUZ;JUNCACEAE 20 001-ALT - 001-ALT 0.00 0.00 15.23 9.78 5.76 0.00 0.00 0.00 17.18 1.95 0.00P-DP 16.00HA RA SUZ;JUNCACEAE 20 002-ALT - 002-ALT 0.00 0.00 37.09 18.85 14.04 0.00 0.00 0.00 41.83 4.74 0.00P-DP 30.31HA RA SUZ;JUNCACEAE 20 003-ALT - 003-ALT 0.00 0.00 131.05 85.15 49.60 0.00 0.00 0.00 147.82 16.77 0.00P-DP 14.78HA RB SU69;NAC ROYALTY 33 H 001 - 001 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00HA RB SU74;NAC ROYALTY 28 H 001 - 001 0.00 0.00 7.32 6.44 2.77 0.00 0.00 0.00 8.26 0.94 0.00P-DP 3.06HA RB SU77;WAHL 27 H 001 - 001 0.00 0.00 132.84 81.31 50.28 0.00 0.00 0.00 149.84 16.99 0.00P-DP 20.87HA RB SU90;NRG 29-12-10 H 001 - 001 0.00 0.00 738.79 562.26 267.48 0.00 0.00 0.00 829.20 90.41 0.00P-DP 50.00HA RB SU90;NRG 29-12-10 H 002-ALT - 002-ALT 0.00 0.00 21.81 19.65 8.26 0.00 0.00 0.00 24.60 2.79 0.00P-DP 2.50HA RB SU92;NAC ROYALTY 34 H 001 - 001 0.00 0.00 18.24 10.14 0.13 0.30 0.00 19.91 0.39 2.71 0.00P-DP 33.18HALL TRUST 38 1 - 1 0.65 0.02 19.81 10.06 0.10 0.33 0.00 21.94 0.30 2.94 0.00P-DP 46.83HALL TRUST 38 2 - 2 0.50 0.01 25.58 14.98 0.71 0.38 0.00 25.01 2.44 6.63 0.00P-DP 40.86HALL-PORTER 621-596 A 112 - 112 4.76 0.17 30.02 18.04 1.16 0.40 0.00 26.35 3.98 8.06 0.00P-DP 42.02HALL-PORTER 621-596 A 211 - 211 7.75 0.27 16.08 9.29 0.76 0.19 0.00 12.83 2.61 4.43 0.00P-DP 34.37HALL-PORTER 621-596 B 122 - 122 5.08 0.18 16.28 10.22 0.87 0.18 0.00 12.06 2.98 4.57 0.00P-DP 30.76HALL-PORTER 621-596 B 221 - 221 5.81 0.20 14.53 8.85 0.99 0.13 0.00 8.77 3.40 4.26 0.00P-DP 31.31HALL-PORTER 621-596 B 224 - 224 6.62 0.23 17.18 10.60 0.74 0.22 0.00 14.35 2.55 4.68 0.00P-DP 35.22HALL-PORTER 621-596 C 132 - 132 4.96 0.17 10.98 6.69 0.45 0.14 0.00 9.39 1.55 2.97 0.00P-DP 38.18HALL-PORTER 621-596 C 231R - 231R 3.01 0.11 18.53 11.34 0.84 0.23 0.00 15.11 2.89 5.08 0.00P-DP 36.25HALL-PORTER 621-596 C 233 - 233 5.62 0.20 12.35 7.48 0.25 0.19 0.00 12.93 0.86 3.12 0.00P-DP 38.17HALL-PORTER 621-596 D 142 - 142 1.68 0.06 9.38 6.25 0.24 0.14 0.00 9.37 0.82 2.41 0.00P-DP 32.19HALL-PORTER 621-596 D 241 - 241 1.60 0.06 2.22 1.06 0.50 0.00 0.00 0.00 1.19 0.49 0.00P-DP 50.00HARGROVE, BETTY 1 - 1 1.52 0.05 1.22 0.67 0.06 0.02 0.00 1.14 0.21 0.27 0.00P-DP 44.07HAWKS 55-1-28 UNIT 1H - 1H 0.14 0.01 4.75 3.24 2.27 0.00 0.00 0.00 6.39 1.64 0.00P-DP 34.27HENDERSHOT 210471 1A - 1A 0.00 0.00 5.14 3.49 2.45 0.00 0.00 0.00 6.90 1.77 0.00P-DP 35.20HENDERSHOT 210471 2B - 2B 0.00 0.00 8.26 6.40 0.07 0.13 0.00 8.31 0.24 0.63 0.00P-DP 11.31HOERMANN UNIT 1H - 1H 0.33 0.01 30.71 16.02 0.69 0.42 0.00 27.54 2.46 2.64 0.00P-DP 50.00HOERMANN UNIT 2H - 2H 3.36 0.14 95.11 53.92 2.68 1.25 0.00 81.10 9.60 8.71 0.00P-DP 37.12HOERMANN UNIT 3H - 3H 13.12 0.56 96.95 53.66 2.17 1.34 0.00 86.99 7.78 8.46 0.00P-DP 38.61HOERMANN UNIT 4H - 4H 10.64 0.45 2.95 1.62 0.28 0.03 0.00 1.99 1.01 0.63 0.00P-DP 44.71HORNSILVER 1H - 1H 0.59 0.02 3.05 1.71 0.13 0.03 0.00 2.10 0.42 0.34 0.00P-DP 31.80HULING 'A' 18-7 ESL (ALLOC) 1HA - 1HA 0.87 0.04 0.75 0.47 0.02 0.01 0.00 0.58 0.08 0.08 0.00P-DP 17.28HULING 'D' 18-7 ESL (ALLOC) 4HS - 4HS 0.17 0.01 19.15 11.21 0.31 0.30 0.00 19.45 0.96 2.87 0.00P-DP 50.00HYDRA 45-4 UNIT 1 112 - 112 1.61 0.04 16.10 9.45 0.29 0.25 0.00 16.11 0.90 2.41 0.00P-DP 50.00HYDRA 45-4 UNIT 1 122 - 122 1.50 0.04 26.52 15.41 0.43 0.41 0.00 26.96 1.32 3.97 0.00P-DP 50.00HYDRA 45-4 UNIT 1 124 - 124 2.22 0.06 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 28.89 16.74 0.49 0.45 0.00 29.18 1.51 4.33 0.00P-DP 50.00HYDRA 45-4 UNIT 1 132 - 132 2.53 0.06 17.46 10.13 0.34 0.26 0.00 17.28 1.05 2.62 0.00P-DP 50.00HYDRA 45-4 UNIT 1 142 - 142 1.75 0.04 20.46 11.91 0.20 0.33 0.00 21.88 0.61 3.05 0.00P-DP 50.00HYDRA 45-4 UNIT 1 211 - 211 1.03 0.03 28.22 17.50 0.30 0.46 0.00 29.93 0.94 4.21 0.00P-DP 50.00HYDRA 45-4 UNIT 1 221 - 221 1.57 0.04 21.19 12.61 0.41 0.32 0.00 20.95 1.28 3.18 0.00P-DP 50.00HYDRA 45-4 UNIT 1 223 - 223 2.14 0.05 17.38 10.10 0.24 0.27 0.00 17.94 0.76 2.60 0.00P-DP 50.00HYDRA 45-4 UNIT 1 231 - 231 1.28 0.03 25.35 15.74 0.43 0.39 0.00 25.61 1.32 3.80 0.00P-DP 50.00HYDRA 45-4 UNIT 1 241 - 241 2.21 0.06 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 38.64JACKSON A 34-166-175 5201H - 5201H 0.00 0.00 42.31 22.31 1.21 0.55 0.00 35.88 4.32 3.81 0.00P-DP 46.54JANAK UNIT 3H - 3H 5.91 0.25 45.89 24.90 1.29 0.60 0.00 39.10 4.62 4.14 0.00P-DP 50.00JANAK UNIT 4H - 4H 6.31 0.27 60.16 28.90 2.44 0.70 0.00 45.44 8.72 5.93 0.00P-DP 50.00JANAK UNIT 5H - 5H 11.93 0.51 34.01 23.11 1.08 0.43 0.00 27.85 3.86 2.98 0.00P-DP 30.27JANAK UNIT 7L - 7L 5.28 0.22 49.58 29.23 1.55 0.63 0.00 40.78 5.54 4.31 0.00P-DP 50.00JANAK-LOOS 6L - 6L 7.57 0.32 0.13 0.06 0.01 0.00 0.00 0.08 0.02 0.02 0.00P-DP 40.37JMW NAIL 10 1 - 1 0.04 0.00 0.14 0.06 0.01 0.00 0.00 0.05 0.04 0.02 0.00P-DP 50.00JMW NAIL 10 2 - 2 0.07 0.00 0.12 0.06 0.01 0.00 0.00 0.06 0.03 0.02 0.00P-DP 36.05JMW NAIL 10 3 - 3 0.05 0.00 0.14 0.07 0.01 0.00 0.00 0.09 0.03 0.02 0.00P-DP 40.23JMW NAIL 10 4 - 4 0.05 0.00 0.20 0.10 0.01 0.00 0.00 0.12 0.04 0.03 0.00P-DP 50.00JMW NAIL 10A 3 - 3 0.07 0.00 0.24 0.12 0.01 0.00 0.00 0.18 0.04 0.04 0.00P-DP 50.00JMW NAIL 10A 4 - 4 0.06 0.00 1.22 0.99 0.47 0.00 0.00 0.00 1.48 0.26 0.00P-DP 5.92JUR RA SUG;OLYMPIA MIN 30 H 001 - 001 0.00 0.00 16.23 8.37 0.87 0.16 0.00 10.59 3.12 1.75 0.00P-DP 45.59KAISER UNIT 1H - 1H 4.27 0.18 24.78 12.86 1.02 0.29 0.00 18.59 3.65 2.44 0.00P-DP 48.22KAISER UNIT 4H - 4H 4.98 0.21 39.60 19.59 1.65 0.45 0.00 29.55 5.90 3.92 0.00P-DP 50.00KAISER UNIT 5H - 5H 8.07 0.34 10.24 5.46 0.92 0.11 0.00 6.79 2.20 1.55 0.00P-DP 45.14KENOSHA 4441 1H - 1H 2.81 0.09 12.34 6.47 0.64 0.16 0.00 10.44 1.52 1.56 0.00P-DP 49.02KENOSHA 4441 B 2H - B 2H 1.94 0.06 81.93 51.21 0.93 1.32 0.00 86.50 2.89 12.30 0.00P-DP 43.10KENTEX-HARRISON 35A 1H - 1H 4.84 0.12 91.33 55.89 1.55 1.41 0.00 92.31 4.82 13.86 0.00P-DP 42.52KENTEX-HARRISON 35B 2H - 2H 8.07 0.20 89.89 53.45 0.97 1.46 0.00 95.32 3.01 13.48 0.00P-DP 46.24KENTEX-HARRISON 35C 3H - 3H 5.04 0.13 78.28 48.27 1.48 1.19 0.00 77.94 4.59 11.93 0.00P-DP 40.61KENTEX-HARRISON 35D 4H - 4H 7.68 0.19 6.31 3.22 0.23 0.09 0.00 5.80 0.55 0.73 0.00P-DP 42.16KEYHOLE 43 1H - 1H 0.70 0.02 26.37 15.42 0.36 0.40 0.00 26.29 1.23 2.71 0.00P-DP 50.00KINGSLEY 10HK - 10HK 1.55 0.07 36.43 21.23 0.52 0.55 0.00 36.22 1.75 3.74 0.00P-DP 50.00KINGSLEY 3HK - 3HK 2.20 0.10 100.78 59.40 1.15 1.55 0.00 102.18 3.91 10.23 0.00P-DP 50.00KINGSLEY 4HJ - 4HJ 4.92 0.23 88.42 52.22 1.51 1.30 0.00 86.08 5.11 9.20 0.00P-DP 50.00KINGSLEY 5HK - 5HK 6.43 0.30 90.65 52.47 2.10 1.28 0.00 84.26 7.11 9.68 0.00P-DP 50.00KINGSLEY 6HF - 6HF 8.96 0.41 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 26.83 15.68 0.36 0.41 0.00 26.79 1.24 2.75 0.00P-DP 50.00KINGSLEY 7HJ - 7HJ 1.56 0.07 26.57 15.57 0.39 0.40 0.00 26.32 1.32 2.74 0.00P-DP 50.00KINGSLEY 8HK - 8HK 1.67 0.08 26.10 14.83 0.29 0.40 0.00 26.52 0.98 2.65 0.00P-DP 50.00KINGSLEY 9HJ - 9HJ 1.24 0.06 11.98 7.04 0.18 0.18 0.00 11.87 0.62 1.28 0.00P-DP 43.66KRAKEN 10-3 E1 251 - 251 0.78 0.04 25.59 15.51 0.31 0.39 0.00 25.80 1.06 2.61 0.00P-DP 50.00KRAKEN 10-3 UNIT 2 153 - 153 1.34 0.06 30.39 18.48 0.35 0.47 0.00 30.77 1.20 3.09 0.00P-DP 50.00KRAKEN 10-3 UNIT 2 162 - 162 1.51 0.07 45.60 26.95 0.49 0.70 0.00 46.47 1.66 4.62 0.00P-DP 50.00KRAKEN 10-3 UNIT 2 171 - 171 2.09 0.10 35.70 21.33 0.61 0.55 0.00 36.00 1.89 5.35 0.00P-DP 50.00KRAKEN 10-3 UNIT 2 181 - 181 3.17 0.08 23.40 14.00 0.43 0.36 0.00 23.37 1.32 3.51 0.00P-DP 50.00KRAKEN 10-3 UNIT 2 183 - 183 2.22 0.06 18.76 12.27 0.21 0.29 0.00 19.10 0.71 1.95 0.00P-DP 38.07KRAKEN 10-3 UNIT 2 252 - 252 0.89 0.04 35.48 20.78 0.37 0.55 0.00 36.24 1.25 3.59 0.00P-DP 50.00KRAKEN 10-3 UNIT 2 261 - 261 1.57 0.07 34.43 21.24 0.41 0.53 0.00 34.83 1.37 3.50 0.00P-DP 50.00KRAKEN 10-3 UNIT 2 272 - 272 1.73 0.08 18.61 10.89 0.21 0.30 0.00 19.66 0.65 2.78 0.00P-DP 50.00KRAKEN 10-3 UNIT 2 273 - 273 1.08 0.03 30.25 19.27 0.59 0.46 0.00 29.89 1.84 4.54 0.00P-DP 50.00KRAKEN 10-3 UNIT 2 282 - 282 3.07 0.08 256.82 172.94 122.43 0.00 0.00 0.00 345.26 88.45 0.00P-DP 23.47KRUPA 210483 3A - 3A 0.00 0.00 133.62 81.67 63.70 0.00 0.00 0.00 179.64 46.02 0.00P-DP 32.29KRUPA 211259 2A - 2A 0.00 0.00 47.70 27.43 0.69 0.72 0.00 47.60 2.34 3.85 0.00P-DP 22.08KUBENKA UNIT 1H - 1H 1.61 0.07 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00L E STARTZELL 2 - 2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00L E STARTZELL UNIT BR 19 4 - 4 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00L E STARTZELL UNIT BR 19 5 - 5 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00LANE, ROWENA 11D - 11D 0.00 0.00 7.15 5.17 0.81 0.02 0.00 1.31 2.92 1.06 0.00P-DP 21.98LANGHOFF UNIT A 1H - 1H 3.99 0.17 3.63 2.55 0.11 0.05 0.00 3.03 0.39 0.33 0.00P-DP 14.98LANGHOFF UNIT A 2H - 2H 0.54 0.02 4.75 2.97 0.37 0.03 0.00 2.20 1.33 0.58 0.00P-DP 35.95LANGHOFF UNIT A 3H - 3H 1.81 0.08 5.22 3.29 0.15 0.07 0.00 4.42 0.53 0.47 0.00P-DP 20.68LANGHOFF UNIT A 4H - 4H 0.73 0.03 71.02 42.69 3.55 0.73 0.00 47.80 12.72 6.88 0.00P-DP 50.00LANGHOFF UNIT A 8L - 8L 17.39 0.74 47.28 28.77 2.41 0.48 0.00 31.49 8.61 4.60 0.00P-DP 50.00LANGHOFF UNIT A 9L - 9L 11.78 0.50 11.17 7.56 0.58 0.11 0.00 7.33 2.09 1.10 0.00P-DP 50.00LANGHOFF UNIT B 701 - 701 2.85 0.12 5.42 2.93 0.22 0.08 0.00 4.85 0.53 0.65 0.00P-DP 45.86LAURA WILDER 72-69 UNIT A 3H - 3H 0.68 0.02 1.78 1.00 0.06 0.03 0.00 1.64 0.15 0.21 0.00P-DP 36.48LAURA WILDER 72-69 UNIT B 4HL - 4HL 0.20 0.01 22.62 17.21 8.56 0.00 0.00 0.00 25.51 2.89 0.00P-DP 14.45LAWSON 31-30 HC 001 - 001 0.00 0.00 22.89 17.44 8.66 0.00 0.00 0.00 25.82 2.93 0.00P-DP 14.48LAWSON 31-30-19 HC 002 - 002 0.00 0.00 31.01 23.63 11.74 0.00 0.00 0.00 34.98 3.97 0.00P-DP 14.48LAWSON 31-30-19 HC 003 - 003 0.00 0.00 9.33 6.38 0.25 0.15 0.00 9.66 0.91 1.78 0.00P-DP 16.01LEE 34-154 1H - 1H 0.53 0.02 3.74 1.90 0.06 0.06 0.00 4.11 0.21 0.70 0.00P-DP 32.37LEEDE UNIT 7 1H - 1H 0.12 0.00 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 2.63 1.34 0.04 0.04 0.00 2.88 0.16 0.49 0.00P-DP 28.74LEEDE UNIT 7 2H - 2H 0.09 0.00 1.30 0.85 0.02 0.02 0.00 1.29 0.06 0.13 0.00P-DP 14.23LONG 18 1 - 1 0.08 0.00 5.88 4.50 0.15 0.08 0.00 5.10 0.54 0.50 0.00P-DP 13.88LOOS UNIT 10H - 10H 0.74 0.03 120.31 69.25 5.05 1.36 0.00 88.66 18.06 11.11 0.00P-DP 50.00LOOS UNIT 11L - 11L 24.70 1.05 93.74 54.26 4.57 0.98 0.00 63.97 16.38 9.00 0.00P-DP 50.00LOOS UNIT 12L - 12L 22.39 0.95 2.53 1.84 0.06 0.04 0.00 2.28 0.20 0.22 0.00P-DP 11.83LOOS UNIT 1H - 1H 0.27 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00LOOS UNIT 2H - 2H 0.00 0.00 6.99 3.69 0.27 0.08 0.00 5.42 0.95 0.68 0.00P-DP 35.37LOOS UNIT 3H - 3H 1.30 0.06 6.22 3.70 0.19 0.08 0.00 5.12 0.70 0.54 0.00P-DP 24.18LOOS UNIT 8H - 8H 0.95 0.04 61.66 39.16 1.45 0.84 0.00 54.51 5.18 5.12 0.00P-DP 50.00LOOS UNIT 9H - 9H 7.09 0.30 0.94 0.50 0.05 0.01 0.00 0.79 0.12 0.12 0.00P-DP 30.55LOST SADDLE 45 1H - 1H 0.15 0.00 5.82 3.34 0.22 0.08 0.00 5.12 0.77 1.56 0.00P-DP 44.85LRT UNIT 2 ALLOCATION 2318AH - 2318AH 1.50 0.05 0.17 0.10 0.00 0.00 0.00 0.17 0.02 0.04 0.00P-DP 34.48MABEE 22A 1H - 1H 0.03 0.00 0.10 0.06 0.00 0.00 0.00 0.11 0.00 0.01 0.00P-DP 50.00MABEE DDA J8 3HK - 3HK 0.00 0.00 0.10 0.06 0.00 0.00 0.00 0.10 0.01 0.03 0.00P-DP 50.00MABEE-ELKIN W16B 2H - 2H 0.02 0.00 0.67 0.41 0.02 0.01 0.00 0.60 0.09 0.18 0.00P-DP 36.30MABEE-STIMSON 22B 2H - 2H 0.17 0.01 0.08 0.05 0.00 0.00 0.00 0.07 0.01 0.02 0.00P-DP 35.43MABEE-TREDAWAY W16A 1H - 1H 0.02 0.00 2.45 1.61 0.15 0.03 0.00 1.88 0.50 0.26 0.00P-DP 27.19MACHICEK UNIT 1H - 1H 0.34 0.02 5.38 2.83 0.45 0.06 0.00 3.94 1.63 1.14 0.00P-DP 47.22MARY GRACE 201-202 UNIT 1H - 1H 0.95 0.03 3.94 2.31 0.28 0.05 0.00 3.15 1.02 0.82 0.00P-DP 41.22MARY GRACE 201-202 UNIT 3H - 3H 0.59 0.02 4.16 2.60 0.05 0.07 0.00 4.38 0.15 0.63 0.00P-DP 37.71MARYRUTH-ANDERSON 47C 103H - 103H 0.26 0.01 2.89 1.86 0.05 0.04 0.00 2.94 0.15 0.44 0.00P-DP 33.16MARYRUTH-ANDERSON 47D 104H - 104H 0.24 0.01 3.56 2.34 0.06 0.06 0.00 3.63 0.17 0.54 0.00P-DP 33.95MARYRUTH-ANDERSON 47E 105H - 105H 0.29 0.01 3.91 2.35 0.04 0.06 0.00 4.13 0.13 0.59 0.00P-DP 40.27MARYRUTH-ANDERSON 47F 106H - 106H 0.22 0.01 326.71 190.80 85.80 0.00 0.00 0.00 273.69 115.12 0.00P-DP 29.85MATTIE 18-11-5 6H - 6H 168.14 6.62 208.35 130.85 54.71 0.00 0.00 0.00 174.54 73.41 0.00P-DP 23.03MATTIE 18-11-5 7H - 7H 107.23 4.22 342.87 202.52 88.52 0.13 0.00 7.79 282.37 120.77 0.00P-DP 29.88MATTIE 18-11-5 8H - 8H 173.47 6.83 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00MCCONNELL 4 - 4 0.00 0.00 0.29 0.16 0.02 0.00 0.00 0.21 0.05 0.03 0.00P-DP 21.41MEADOR, J. J. 3 - 3 0.06 0.00 1.45 1.28 0.33 0.00 0.00 0.00 1.21 0.15 0.00P-DP 2.70MEHAFFEY - BURNEM 1 - 1 0.39 0.02 0.14 0.07 0.00 0.00 0.00 0.16 0.00 0.03 0.00P-DP 50.00MELISSA A 1 - 1 0.00 0.00 1.33 0.75 0.09 0.02 0.00 1.11 0.31 0.27 0.00P-DP 37.69MERIDITH 183 UNIT 1H - 1H 0.18 0.01 3.07 1.54 0.15 0.03 0.00 2.31 0.50 0.36 0.00P-DP 50.00MIDDLETON 21 1 - 1 0.63 0.03 15.05 9.30 0.79 0.17 0.00 10.94 2.45 2.44 0.00P-DP 22.89MIMS 32H 3306BH - 3306BH 4.10 0.10 16.45 10.43 0.80 0.19 0.00 12.45 2.49 2.65 0.00P-DP 21.23MIMS 32H 3307BH - 3307BH 4.16 0.11 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 17.38 11.17 0.48 0.25 0.00 16.05 1.50 2.69 0.00P-DP 23.20MIMS 32H 3315AH - 3315AH 2.52 0.06 12.23 7.92 0.82 0.11 0.00 7.46 2.54 2.03 0.00P-DP 19.14MIMS 32H 3317AH - 3317AH 4.26 0.11 12.09 7.82 0.33 0.17 0.00 11.21 1.03 1.87 0.00P-DP 20.03MIMS 32H 3318AH - 3318AH 1.72 0.04 14.09 8.99 0.62 0.17 0.00 11.17 1.93 2.25 0.00P-DP 21.58MIMS 32H 3326SH - 3326SH 3.23 0.08 12.29 7.89 0.33 0.17 0.00 11.41 1.04 1.90 0.00P-DP 20.34MIMS 32H 3327SH - 3327SH 1.74 0.04 20.41 12.66 0.47 0.30 0.00 19.67 1.45 3.13 0.00P-DP 25.49MIMS 32H 3345SH - 3345SH 2.42 0.06 9.07 6.77 0.13 0.14 0.00 9.38 0.40 1.37 0.00P-DP 13.52MIMS 32H 3347SH - 3347SH 0.66 0.02 30.14 19.43 0.62 0.45 0.00 29.58 1.94 4.61 0.00P-DP 28.22MIMS 32H 3348SH - 3348SH 3.24 0.08 112.03 78.41 43.56 0.00 0.00 0.00 145.05 33.02 0.00P-DP 20.88MINGO S CRC JF 4H - 4H 0.00 0.00 345.72 222.94 134.42 0.00 0.00 0.00 447.63 101.91 0.00P-DP 28.18MINGO SE CRC JF 6H - 6H 0.00 0.00 54.61 38.44 21.23 0.00 0.00 0.00 70.71 16.10 0.00P-DP 21.24MINGO SW CRC JF 2H - 2H 0.00 0.00 151.96 113.04 59.08 0.00 0.00 0.00 196.75 44.79 0.00P-DP 15.74MINGO W CRC JF 8H - 8H 0.00 0.00 24.60 17.65 0.41 0.37 0.00 24.30 1.38 2.02 0.00P-DP 12.49MOLNOSKEY UNIT 1H - 1H 0.95 0.04 83.15 47.93 1.74 1.22 0.00 80.30 5.89 7.09 0.00P-DP 34.89MOLNOSKEY UNIT 2H - 2H 4.05 0.19 0.25 0.19 0.01 0.00 0.00 0.26 0.02 0.05 0.00P-DP 8.50MONROE 34-158 UNIT 1H - 1H 0.01 0.00 0.09 0.08 0.00 0.00 0.00 0.11 0.00 0.02 0.00P-DP 3.97MONROE 34-158 UNIT 2H - 2H 0.00 0.00 0.42 0.27 0.01 0.01 0.00 0.46 0.02 0.08 0.00P-DP 15.44MONROE 34-158 UNIT 3H - 3H 0.01 0.00 0.01 0.01 0.00 0.00 0.00 0.02 0.00 0.00 0.00P-DP 1.09MONROE 34-158 UNIT 4H - 4H 0.00 0.00 12.03 6.99 0.68 0.19 0.00 12.06 2.45 2.51 0.00P-DP 43.75Mud Hen 1 ** 0.03 0.00 19.15 11.46 0.65 0.32 0.00 20.56 2.34 3.79 0.00P-DP 48.36Mud Hen 2 ** 0.03 0.00 17.62 9.90 0.91 0.28 0.00 17.93 3.29 3.64 0.00P-DP 48.78Mud Hen 3 ** 0.05 0.00 19.03 11.32 0.90 0.30 0.00 19.64 3.24 3.89 0.00P-DP 48.43Mud Hen 4 ** 0.04 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00N A C R C 1 - 15 ACRES 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00N A C R C 5-132 - 5-132 0.00 0.00 555.78 371.23 216.10 0.00 0.00 0.00 719.60 163.82 0.00P-DP 19.99NAC 3H-20 - 3H-20 0.00 0.00 257.33 159.16 100.05 0.00 0.00 0.00 333.18 75.85 0.00P-DP 50.00NAC 3P-20 - 3P-20 0.00 0.00 505.89 340.56 196.70 0.00 0.00 0.00 655.00 149.12 0.00P-DP 19.08NAC 4H-20 - 4H-20 0.00 0.00 365.25 260.98 142.02 0.00 0.00 0.00 472.92 107.66 0.00P-DP 16.27NAC B WYN JF 1H - 1H 0.00 0.00 257.17 199.69 99.99 0.00 0.00 0.00 332.98 75.81 0.00P-DP 11.61NAC B WYN JF 3H - 3H 0.00 0.00 349.26 254.97 135.80 0.00 0.00 0.00 452.21 102.95 0.00P-DP 15.24NAC B WYN JF 5H - 5H 0.00 0.00 449.75 298.14 174.87 0.00 0.00 0.00 582.32 132.57 0.00P-DP 20.43NAC GAS UNIT B 3H-3 - 3H-3 0.00 0.00 0.35 0.17 0.01 0.00 0.00 0.31 0.03 0.05 0.00P-DP 50.00NAIL RANCH 10 1 - 1 0.06 0.00 0.33 0.17 0.01 0.01 0.00 0.33 0.02 0.05 0.00P-DP 50.00NAIL RANCH 10 2 - 2 0.04 0.00 0.37 0.18 0.01 0.01 0.00 0.37 0.02 0.06 0.00P-DP 50.00NAIL RANCH 10 3 - 3 0.03 0.00 0.52 0.26 0.01 0.01 0.00 0.48 0.04 0.08 0.00P-DP 50.00NAIL RANCH 10 4 - 4 0.07 0.00 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 14.11 7.05 0.51 0.19 0.00 12.56 1.72 1.34 0.00P-DP 48.33NANCY 1H - 1H 1.18 0.05 0.31 0.15 0.01 0.00 0.00 0.28 0.03 0.05 0.00P-DP 50.00NE NAIL 10 1 - 1 0.05 0.00 0.64 0.30 0.03 0.01 0.00 0.52 0.08 0.10 0.00P-DP 50.00NE NAIL 10 2 - 2 0.14 0.00 0.29 0.15 0.01 0.00 0.00 0.23 0.04 0.04 0.00P-DP 50.00NE NAIL 10 3 - 3 0.06 0.00 0.12 0.06 0.01 0.00 0.00 0.08 0.02 0.02 0.00P-DP 49.20NE NAIL 10 4 - 4 0.04 0.00 0.13 0.06 0.01 0.00 0.00 0.10 0.02 0.02 0.00P-DP 50.00NE NAIL 10 5 - 5 0.04 0.00 12.29 6.68 0.44 0.16 0.00 10.42 1.50 1.52 0.00P-DP 38.67NEWTON 43A 1HE - 1HE 1.89 0.09 10.92 6.90 0.17 0.16 0.00 10.80 0.57 1.17 0.00P-DP 30.31NEWTON 43A 2HK - 2HK 0.72 0.03 1.24 0.73 0.06 0.01 0.00 0.96 0.20 0.16 0.00P-DP 21.42NEWTON 43B 3HJ - 3HJ 0.25 0.01 2.28 1.16 0.14 0.02 0.00 1.52 0.46 0.28 0.00P-DP 50.00NEWTON 43B 4HE - 4HE 0.58 0.03 3.38 1.77 0.16 0.04 0.00 2.58 0.53 0.40 0.00P-DP 50.00NEWTON 43B 5HK - 5HK 0.67 0.03 8.13 4.13 0.26 0.11 0.00 7.06 0.87 0.90 0.00P-DP 50.00NEWTON 43BK 4HE - 4HE 1.10 0.05 15.95 8.13 0.45 0.22 0.00 14.26 1.52 1.74 0.00P-DP 50.00NEWTON 43BK 5HK - 5HK 1.92 0.09 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 35.72NEWTON 43C 6HJ - 6HJ 0.00 0.00 69.24 40.47 18.09 0.01 0.00 0.49 57.70 24.40 0.00P-DP 24.82NM HARRISON 16-11-5 10H - 10H 35.45 1.40 105.83 67.66 26.38 0.12 0.00 7.24 84.15 37.25 0.00P-DP 24.92NM HARRISON 16-11-5 6H - 6H 51.69 2.04 79.52 47.15 20.87 0.00 0.00 0.08 66.57 28.02 0.00P-DP 24.69NM HARRISON 16-11-5 8H - 8H 40.90 1.61 297.64 227.06 115.73 0.00 0.00 0.00 385.37 87.73 0.00P-DP 14.06NOLAN NE CRC JF 3H - 3H 0.00 0.00 1,665.70 1,010.16 647.66 0.00 0.00 0.00 2,156.69 490.99 0.00P-DP 37.56NOLAN NW CRC JF 1H - 1H 0.00 0.00 635.50 418.32 247.09 0.00 0.00 0.00 822.82 187.32 0.00P-DP 24.95NOLAN S CRC JF 2H - 2H 0.00 0.00 554.10 379.67 215.44 0.00 0.00 0.00 717.42 163.33 0.00P-DP 22.21NOLAN S CRC JF 4H - 4H 0.00 0.00 565.24 383.09 219.78 0.00 0.00 0.00 731.85 166.61 0.00P-DP 22.90NOLAN S CRC JF 6H - 6H 0.00 0.00 67.81 40.37 1.11 1.05 0.00 68.89 3.44 10.28 0.00P-DP 39.28NORRIS UNIT 32-H 3301BH - 3301BH 5.75 0.15 88.69 51.86 1.86 1.33 0.00 86.81 5.77 13.56 0.00P-DP 42.65NORRIS UNIT 32-H 3303BH - 3303BH 9.66 0.24 60.07 35.88 0.53 0.99 0.00 64.61 1.66 8.98 0.00P-DP 37.89NORRIS UNIT 32-H 3304BH - 3304BH 2.78 0.07 56.50 32.94 1.13 0.85 0.00 55.73 3.51 8.63 0.00P-DP 50.00NORRIS UNIT 32-H 3312AH - 3312AH 5.88 0.15 75.64 44.78 1.99 1.08 0.00 70.76 6.20 11.69 0.00P-DP 40.60NORRIS UNIT 32-H 3313AH - 3313AH 10.37 0.26 83.31 50.54 1.31 1.30 0.00 85.04 4.07 12.61 0.00P-DP 41.20NORRIS UNIT 32-H 3322SH - 3322SH 6.81 0.17 154.04 98.05 2.75 2.36 0.00 154.57 8.56 23.42 0.00P-DP 46.81NORRIS UNIT 32-H 3323SH - 3323SH 14.33 0.36 113.32 67.82 2.11 1.73 0.00 113.05 6.55 17.25 0.00P-DP 44.97NORRIS UNIT 32-H 3361DH - 3361DH 10.97 0.28 93.67 56.44 2.09 1.38 0.00 90.62 6.51 14.37 0.00P-DP 42.65NORRIS UNIT 32-H 3363DH - 3363DH 10.90 0.28 93.47 56.04 2.30 1.36 0.00 88.77 7.14 14.39 0.00P-DP 42.72NORRIS UNIT 32-H 3364DH - 3364DH 11.95 0.30 75.32 45.29 0.94 1.20 0.00 78.83 2.93 11.33 0.00P-DP 40.26NORRIS UNIT 32-H 3371JH - 3371JH 4.90 0.12 75.83 45.21 1.19 1.18 0.00 77.43 3.69 11.48 0.00P-DP 40.50NORRIS UNIT 32-H 3373JH - 3373JH 6.18 0.16 84.40 49.87 1.17 1.33 0.00 87.37 3.65 12.73 0.00P-DP 41.89NORRIS UNIT 32-H 3374JH - 3374JH 6.11 0.15 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 84.40 49.54 1.31 1.32 0.00 86.31 4.06 12.77 0.00P-DP 42.02NORRIS-MIMS ALLOCATION 3315AH - 3315AH 6.80 0.17 93.30 55.84 2.22 1.36 0.00 89.21 6.90 14.35 0.00P-DP 42.74NORRIS-MIMS ALLOCATION 3325SH - 3325SH 11.54 0.29 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00NORTH AMERICAN COAL 1S - 1S 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00NORTH AMERICAN COAL 2S - 2S 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00NORTH AMERICAN COAL 3A - 3A 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00NORTH AMERICAN COAL CO 4 - 4 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00NORTH AMERICAN COAL CORP 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00NORTH AMERICAN COAL CORP 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00NORTH AMERICAN COAL CORP 2 - 2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00NORTH AMERICAN COAL CORP 3 - 3 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00NORTH AMERICAN COAL CORP BR 19 UNIT 2 - 2 0.00 0.00 31.67 17.04 11.11 0.00 0.00 0.00 41.37 9.70 0.00P-DP 23.37NORTH AMERICAN COAL GAS UNIT 1 - 1 0.00 0.00 52.77 47.02 13.76 0.01 0.00 0.47 43.91 18.59 0.00P-DP 4.38NORTH AMERICAN COAL ROYALTY CO BUELL 1 - 1 26.97 1.06 345.60 222.91 90.54 0.02 0.00 1.11 288.82 121.77 0.00P-DP 20.97NORTH AMERICAN COAL ROYALTY CO BUELL 8H - 8H 177.44 6.99 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00NORTH AMERICAN COAL ROYALTY CO. 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00NORTH AMERICAN COAL ROYALTY CO. 2 - 2 0.00 0.00 17.43 10.92 0.28 0.28 0.00 18.91 0.97 4.35 0.00P-DP 34.89OLDHAM-GRAHAM 35A 1H - 1H 1.90 0.07 29.75 18.15 0.63 0.46 0.00 30.89 2.18 7.55 0.00P-DP 41.39OLDHAM-GRAHAM 35B 2H - 2H 4.24 0.15 20.24 12.93 0.31 0.33 0.00 22.16 1.06 5.03 0.00P-DP 36.04OLDHAM-GRAHAM 35C 3H - 3H 2.06 0.07 32.77 19.49 1.07 0.46 0.00 30.56 3.68 8.63 0.00P-DP 43.07OLDHAM-GRAHAM 35D 4H - 4H 7.16 0.25 15.14 9.57 0.26 0.24 0.00 16.25 0.91 3.79 0.00P-DP 33.16OLDHAM-GRAHAM 35E 5H - 5H 1.77 0.06 24.55 15.44 0.45 0.39 0.00 26.14 1.56 6.17 0.00P-DP 37.08OLDHAM-GRAHAM 35F #6H ** 3.03 0.11 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00PALOS 01-12-241 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00PALOS 02-10-239 0.00 0.00 10.72 9.96 4.29 0.00 0.00 0.00 14.29 3.58 0.00P-DP 1.59PALOS 02-16-240 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00PALOS 03-06-245 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00PALOS 03-10-232 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00PALOS 03-14-233 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00PALOS 03-16-231 0.00 0.00 0.46 0.30 0.06 0.00 0.00 0.00 0.21 0.16 0.00P-DP 11.07PARKS FIELD UNIT #2 2401 - 2401 0.41 0.01 14.62 7.54 0.82 0.16 0.00 10.47 2.81 4.14 0.00P-DP 44.07PARKS FIELD UNIT 2 1450BH - 1450BH 5.48 0.19 24.81 13.95 0.57 0.38 0.00 25.34 1.97 6.33 0.00P-DP 45.80PARKS FIELD UNIT 2 1450LH - 1450LH 3.83 0.13 19.45 10.22 0.43 0.30 0.00 20.01 1.49 4.95 0.00P-DP 46.91PARKS FIELD UNIT 2 1451LH - 1451LH 2.90 0.10 3.79 2.08 0.14 0.05 0.00 3.40 0.47 1.01 0.00P-DP 28.56PARKS FIELD UNIT 2 1454H - 1454H 0.92 0.03 14.41 7.81 0.31 0.22 0.00 14.93 1.07 3.66 0.00P-DP 42.83PARKS FIELD UNIT 2 1454LH - 1454LH 2.08 0.07 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 14.41 7.96 0.39 0.21 0.00 14.15 1.35 3.73 0.00P-DP 42.38PARKS FIELD UNIT 2 1455LH - 1455LH 2.64 0.09 14.86 8.45 0.73 0.17 0.00 11.62 2.50 4.12 0.00P-DP 42.00PARKS FIELD UNIT 2 1458CH - 1458CH 4.87 0.17 11.11 6.47 0.48 0.14 0.00 9.24 1.66 3.03 0.00P-DP 37.19PARKS FIELD UNIT 2 1458LH - 1458LH 3.24 0.11 6.57 3.50 0.33 0.08 0.00 5.03 1.14 1.83 0.00P-DP 34.70PARKS FIELD UNIT 2 1863BH - 1863BH 2.23 0.08 6.23 3.44 0.17 0.09 0.00 6.09 0.60 1.62 0.00P-DP 33.36PARKS FIELD UNIT 2 1863LH - 1863LH 1.17 0.04 4.29 2.47 0.09 0.07 0.00 4.44 0.32 1.09 0.00P-DP 28.61PARKS FIELD UNIT 2 1904BH - 1904BH 0.62 0.02 2.04 1.24 0.04 0.03 0.00 2.13 0.15 0.52 0.00P-DP 20.87PARKS FIELD UNIT 2 1921H - 1921H 0.28 0.01 13.39 7.61 0.64 0.16 0.00 10.58 2.21 3.70 0.00P-DP 41.46PARKS FIELD UNIT 2 2001BH - 2001BH 4.31 0.15 10.51 5.62 0.38 0.14 0.00 9.49 1.29 2.79 0.00P-DP 39.63PARKS FIELD UNIT 2 2308BH - 2308BH 2.52 0.09 16.33 8.70 0.47 0.24 0.00 15.79 1.62 4.25 0.00P-DP 44.62PARKS FIELD UNIT 2 2308LH - 2308LH 3.16 0.11 16.99 9.02 0.44 0.25 0.00 16.95 1.50 4.38 0.00P-DP 45.16PARKS FIELD UNIT 2 2308MH - 2308MH 2.92 0.10 5.20 3.34 0.21 0.07 0.00 4.47 0.72 1.40 0.00P-DP 23.65PARKS FIELD UNIT 2 2329LH - 2329LH 1.41 0.05 0.69 0.53 0.05 0.01 0.00 0.38 0.17 0.20 0.00P-DP 8.33PARKS FIELD UNIT 2 2336BH - 2336BH 0.34 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00PARKS FIELD UNIT 2 2346CH - 2346CH 0.00 0.00 5.94 3.17 0.15 0.09 0.00 5.94 0.52 1.53 0.00P-DP 33.60PARKS FIELD UNIT 2 2348H - 2348H 1.02 0.04 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00PARKS FIELD UNIT 2 2401 - 2401 0.00 0.00 3.21 1.92 0.15 0.04 0.00 2.56 0.52 0.89 0.00P-DP 25.16PARKS FIELD UNIT 2 2630H - 2630H 1.02 0.04 7.82 4.22 0.32 0.10 0.00 6.65 1.11 2.12 0.00P-DP 36.20PARKS FIELD UNIT 2 2709H - 2709H 2.17 0.08 0.26 0.15 0.03 0.00 0.00 0.00 0.12 0.09 0.00P-DP 47.90PARKS FIELD UNIT 2401W - 2401W 0.23 0.01 2.52 1.13 0.27 0.01 0.00 0.59 0.93 0.82 0.00P-DP 31.22PARKS FIELD UNIT NO 2 1320H - 1320H 1.82 0.06 6.29 2.83 0.74 0.01 0.00 0.89 2.55 2.11 0.00P-DP 40.27PARKS FIELD UNIT NO. 2 1421H - 1421H 4.97 0.17 5.90 2.50 0.68 0.01 0.00 0.95 2.35 1.97 0.00P-DP 42.49PARKS FIELD UNIT NO. 2 1422H - 1422H 4.57 0.16 0.30 0.22 0.03 0.00 0.00 0.13 0.09 0.09 0.00P-DP 7.99PARKS FIELD UNIT NO. 2 1423H - 1423H 0.17 0.01 1.42 0.68 0.19 0.00 0.00 0.00 0.65 0.50 0.00P-DP 24.46PARKS FIELD UNIT NO. 2 1829H - 1829H 1.27 0.04 1.22 0.63 0.16 0.00 0.00 0.00 0.56 0.43 0.00P-DP 21.44PARKS FIELD UNIT NO. 2 1831H - 1831H 1.09 0.04 3.32 1.38 0.39 0.01 0.00 0.49 1.34 1.11 0.00P-DP 37.24PARKS FIELD UNIT NO. 2 2324H - 2324H 2.61 0.09 0.34 0.24 0.04 0.00 0.00 0.06 0.14 0.11 0.00P-DP 8.99PARKS FIELD UNIT NO. 2 2417H - 2417H 0.26 0.01 0.12 0.06 0.00 0.00 0.00 0.15 0.00 0.03 0.00P-DP 27.85PARKS, CHARLOTTE 14 1 - 1 0.00 0.00 0.06 0.03 0.00 0.00 0.00 0.07 0.00 0.01 0.00P-DP 50.00PARKS, CHARLOTTE 7 1 - 1 0.00 0.00 1.10 0.72 0.04 0.01 0.00 0.98 0.14 0.29 0.00P-DP 23.43PARKS, ROY 306BH - 306BH 0.28 0.01 3.84 2.37 0.04 0.07 0.00 4.41 0.12 0.94 0.00P-DP 37.49PARKS, ROY 306LH - 306LH 0.24 0.01 1.38 0.90 0.07 0.02 0.00 1.06 0.24 0.38 0.00P-DP 25.58PARKS, ROY 307BH - 307BH 0.46 0.02 1.19 0.85 0.02 0.02 0.00 1.26 0.08 0.30 0.00P-DP 20.76PARKS, ROY 307LH - 307LH 0.15 0.01 2.14 1.36 0.06 0.03 0.00 2.07 0.21 0.56 0.00P-DP 31.12PARKS, ROY 308BH - 308BH 0.41 0.01 1.88 1.26 0.07 0.02 0.00 1.64 0.25 0.51 0.00P-DP 24.73PARKS, ROY 308LH - 308LH 0.50 0.02 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 4.83 3.08 0.05 0.08 0.00 5.51 0.17 1.18 0.00P-DP 39.10PARKS, ROY 308MH - 308MH 0.33 0.01 1.70 1.07 0.04 0.03 0.00 1.75 0.13 0.43 0.00P-DP 28.50PARKS, ROY 316CH - 316CH 0.25 0.01 1.36 0.90 0.04 0.02 0.00 1.32 0.13 0.35 0.00P-DP 24.60PARKS, ROY 316LH - 316LH 0.26 0.01 1.39 0.89 0.01 0.02 0.00 1.64 0.03 0.33 0.00P-DP 24.90PARKS, ROY 99H - 99H 0.06 0.00 21.08 13.53 0.65 0.30 0.00 20.07 2.22 5.52 0.00P-DP 33.11PARKS-COYOTE 1506 A 1HM - 1HM 4.32 0.15 28.54 16.81 1.48 0.32 0.00 21.59 5.06 7.97 0.00P-DP 38.58PARKS-COYOTE 1506 B 2HM - 2HM 9.86 0.35 30.14 17.79 1.37 0.37 0.00 24.54 4.70 8.26 0.00P-DP 39.12PARKS-COYOTE 1506 C 3HM - 3HM 9.16 0.32 34.91 20.58 1.53 0.43 0.00 28.95 5.25 9.52 0.00P-DP 40.78PARKS-COYOTE 1506 D 4HM - 4HM 10.23 0.36 27.47 16.41 0.76 0.40 0.00 26.89 2.61 7.12 0.00P-DP 37.81PARKS-COYOTE 1506 E 5HM - 5HM 5.09 0.18 29.77 17.46 0.84 0.44 0.00 29.04 2.87 7.73 0.00P-DP 39.15PARKS-COYOTE 1506 F 6HM - 6HM 5.59 0.20 38.99 23.15 0.76 0.62 0.00 41.15 2.60 9.83 0.00P-DP 41.85PARKS-COYOTE 1506 G 7HM - 7HM 5.07 0.18 2.56 1.40 0.00 0.04 0.00 2.80 0.00 0.25 0.00P-DP 50.00PHILLIPS 7 1 - 1 0.00 0.00 29.89 14.37 1.36 0.33 0.00 21.41 4.87 3.05 0.00P-DP 50.00POTH UNIT 1H - 1H 6.66 0.28 8.53 4.34 0.88 0.08 0.00 5.35 3.18 1.86 0.00P-DP 46.16PRIMA 1H - 1H 1.85 0.06 4.80 2.52 0.40 0.05 0.00 3.51 1.46 1.01 0.00P-DP 38.82PRONTO 1H - 1H 0.85 0.03 0.10 0.06 0.00 0.00 0.00 0.11 0.01 0.02 0.00P-DP 21.59PRUETT 20 2H - 2H 0.01 0.00 0.11 0.06 0.00 0.00 0.00 0.12 0.01 0.02 0.00P-DP 22.65PRUETT 20 4H - 4H 0.00 0.00 0.11 0.07 0.00 0.00 0.00 0.11 0.01 0.02 0.00P-DP 19.70PRUETT 20 5H - 5H 0.01 0.00 0.35 0.17 0.01 0.01 0.00 0.36 0.03 0.07 0.00P-DP 34.84PRUETT 20 6H - 6H 0.02 0.00 0.11 0.07 0.00 0.00 0.00 0.12 0.01 0.02 0.00P-DP 16.91PRUETT 23 2 - 2 0.00 0.00 0.11 0.07 0.00 0.00 0.00 0.12 0.00 0.02 0.00P-DP 17.15PRUETT 23 2H - 2H 0.00 0.00 0.35 0.18 0.01 0.01 0.00 0.37 0.03 0.07 0.00P-DP 29.33PRUETT 23A 1H - 1H 0.02 0.00 0.37 0.19 0.01 0.01 0.00 0.39 0.03 0.07 0.00P-DP 29.85PRUETT 23A 2H - 2H 0.02 0.00 925.31 702.70 359.78 0.00 0.00 0.00 1,198.06 272.75 0.00P-DP 20.74PUGGLE E WYN JF 4H - 4H 0.00 0.00 1,010.74 764.39 392.99 0.00 0.00 0.00 1,308.67 297.93 0.00P-DP 21.75PUGGLE E WYN JF 6H - 6H 0.00 0.00 1,093.75 817.56 425.27 0.00 0.00 0.00 1,416.15 322.40 0.00P-DP 23.76PUGGLE W WYN JF 2H - 2H 0.00 0.00 48.57 29.32 1.95 0.72 0.00 46.97 7.02 9.50 0.00P-DP 37.47QUESO 34-153 UNIT 1H - 1H 4.08 0.13 55.02 31.70 3.36 0.72 0.00 46.96 12.10 11.07 0.00P-DP 40.31QUESO 34-153 UNIT 2H - 2H 7.03 0.23 4.12 2.10 0.15 0.06 0.00 4.12 0.53 0.89 0.00P-DP 48.30QUICK SILVER 55-1-7 UNIT 1H - 1H 0.36 0.02 0.07 0.03 0.00 0.00 0.00 0.07 0.00 0.01 0.00P-DP 38.70QUITO, S. W. (DELAWARE) UNIT 201 - 201 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 49.89QUITO, S. W. (DELAWARE) UNIT 801 - 801 0.00 0.00 11.86 6.84 0.11 0.19 0.00 12.71 0.35 1.77 0.00P-DP 39.13RAGLAND-ANDERSON 47A 1H - 1H 0.58 0.01 10.47 6.33 0.17 0.16 0.00 10.67 0.52 1.59 0.00P-DP 36.64RAGLAND-ANDERSON 47B 2H - 2H 0.86 0.02 10.81 6.23 0.20 0.17 0.00 10.82 0.61 1.64 0.00P-DP 38.10RAGLAND-ANDERSON 47C 3H - 3H 1.02 0.03 1.21 0.67 0.04 0.02 0.00 1.25 0.13 0.26 0.00P-DP 41.91RAINIER 55-1-28 UNIT 1H - 1H 0.09 0.00 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 5.69 3.35 0.13 0.08 0.00 5.06 0.47 0.49 0.00P-DP 22.64RATHKAMP UNIT 1H - 1H 0.65 0.03 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00RATHKAMP UNIT 2H - 2H 0.00 0.00 11.28 5.71 0.67 0.11 0.00 6.83 2.41 1.26 0.00P-DP 50.00RATHKAMP UNIT 3H - 3H 3.30 0.14 9.56 5.64 0.62 0.08 0.00 5.39 2.23 1.11 0.00P-DP 50.00RATHKAMP UNIT 4H - 4H 3.04 0.13 4.94 3.01 0.04 0.09 0.00 5.70 0.15 1.01 0.00P-DP 37.83REED 24 UNIT 2H - 2H 0.10 0.00 1.69 0.95 0.03 0.03 0.00 1.88 0.09 0.35 0.00P-DP 29.07REED 24 UNIT 4H - 4H 0.07 0.00 6.47 3.60 0.13 0.11 0.00 7.05 0.46 1.35 0.00P-DP 42.97REED 24 UNIT 5H - 5H 0.32 0.01 4.63 2.77 0.16 0.07 0.00 4.72 0.53 0.99 0.00P-DP 37.45REED 24 UNIT 7H - 7H 0.37 0.02 4.26 2.44 0.04 0.08 0.00 4.89 0.15 0.87 0.00P-DP 38.21REED 24 UNIT 8H - 8H 0.10 0.00 0.69 0.49 0.33 0.00 0.00 0.00 0.93 0.24 0.00P-DP 16.76REITZ UNIT 5H - 5H 0.00 0.00 5.27 2.93 0.07 0.09 0.00 5.84 0.25 0.98 0.00P-DP 43.81RENDEZVOUS NORTH POOLED UNIT 1LA - 1LA 0.15 0.00 5.93 2.94 0.13 0.10 0.00 6.33 0.46 1.12 0.00P-DP 48.57RENDEZVOUS NORTH POOLED UNIT 9UA - 9UA 0.27 0.01 9.76 6.27 2.80 0.00 0.00 0.00 7.51 1.06 0.00P-DP 35.88RICHARD E LEHMAN SWITZ9BH - SWITZ9BHSU 3.31 0.20 7.27 4.54 2.09 0.00 0.00 0.00 5.60 0.79 0.00P-DP 35.20RICHARD E LEHMAN SWITZ9DH - SWITZ9DHSU 2.47 0.15 11.42 7.36 3.28 0.00 0.00 0.00 8.79 1.24 0.00P-DP 38.36RICHARD E LEHMAN SWITZ9FH - SWITZ9FHSU 3.87 0.23 8.75 5.37 2.51 0.00 0.00 0.00 6.73 0.95 0.00P-DP 37.74RICHARD E LEHMAN SWITZ9HH - SWITZ9HHSU 2.97 0.18 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00RICHMOND 39 1H - 1H 0.00 0.00 2.40 1.28 0.11 0.03 0.00 2.10 0.26 0.29 0.00P-DP 43.05RICHMOND 39 2H - 2H 0.33 0.01 2.12 1.07 0.12 0.03 0.00 1.74 0.29 0.27 0.00P-DP 44.80RICHMOND 39 3H - 3H 0.37 0.01 1.23 0.51 0.00 0.02 0.00 1.35 0.00 0.12 0.00P-DP 46.76RINGNECK DOVE 3 - 3 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00RIPLEY UNIT 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00RIPLEY UNIT 3 - 3 0.00 0.00 31.39 18.55 0.81 0.54 0.00 34.95 2.92 6.52 0.00P-DP 50.00RIVER CAT 57-33 A 0.04 0.00 2.01 0.98 0.10 0.03 0.00 1.88 0.36 0.43 0.00P-DP 43.66ROADRUNNER 1 - 1 0.21 0.01 2.76 1.32 0.08 0.04 0.00 2.86 0.30 0.56 0.00P-DP 50.00ROADRUNNER 2 - 2 0.17 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00ROBERT J CITERONI 2 - 2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00ROBERT J CITERONI 4 - 4 0.00 0.00 5.37 2.74 0.11 0.09 0.00 5.77 0.39 1.01 0.00P-DP 34.12ROCA UNIT 7 1H - 1H 0.23 0.01 2.85 1.57 0.09 0.04 0.00 2.90 0.32 0.55 0.00P-DP 26.51ROCA UNIT 7 2H - 2H 0.18 0.01 224.71 160.76 87.37 0.00 0.00 0.00 290.95 66.24 0.00P-DP 20.42ROXY CRC JF 1H - 1H 0.00 0.00 61.54 44.66 23.93 0.00 0.00 0.00 79.68 18.14 0.00P-DP 20.43ROXY N CRC JF 3H - 3H 0.00 0.00 17.82 13.24 6.93 0.00 0.00 0.00 23.08 5.25 0.00P-DP 18.06ROXY NE CRC JF 5H - 5H 0.00 0.00 669.90 453.20 183.31 0.00 0.00 0.00 584.77 233.74 0.00P-DP 27.47SADIE 33-10-4 1H - 1H 318.86 12.56 1,017.96 641.47 278.56 0.00 0.00 0.00 888.61 355.19 0.00P-DP 34.43SADIE 33-10-4 201H - 201H 484.54 19.09 113.80 75.41 31.14 0.00 0.00 0.00 99.34 39.71 0.00P-DP 32.01SADIE 33-10-4 205H - 205H 54.17 2.13 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 342.95 224.01 93.85 0.00 0.00 0.00 299.37 119.66 0.00P-DP 30.48SADIE 33-10-4 3H - 3H 163.24 6.43 393.43 252.11 107.66 0.00 0.00 0.00 343.43 137.27 0.00P-DP 32.50SADIE 33-10-4 5H - 5H 187.27 7.38 2.13 1.01 0.00 0.04 0.00 2.33 0.00 0.21 0.00P-DP 50.00SAND DOLLAR UNIT 1 - 1 0.00 0.00 37.58 19.43 4.70 0.29 0.00 18.68 11.19 6.57 0.00P-DP 34.89SANTANA 29 2H - 2H 14.29 0.44 23.68 13.21 1.23 0.31 0.00 20.02 2.92 2.99 0.00P-DP 44.91SHADRACH 68 UNIT 134H - 134H 3.73 0.11 25.78 15.33 1.67 0.31 0.00 20.19 3.98 3.48 0.00P-DP 43.61SHADRACH 68 UNIT 1H - 1H 5.09 0.16 33.83 18.64 1.89 0.43 0.00 27.95 4.50 4.36 0.00P-DP 49.24SHADRACH 68 UNIT 223H - 223H 5.74 0.18 26.20 14.89 1.48 0.33 0.00 21.56 3.53 3.39 0.00P-DP 45.10SHADRACH 68 UNIT 2H - 2H 4.50 0.14 34.97 19.31 1.62 0.47 0.00 30.47 3.86 4.29 0.00P-DP 49.59SHADRACH 68 UNIT 324H - 324H 4.93 0.15 28.48 15.72 1.31 0.38 0.00 24.84 3.13 3.49 0.00P-DP 47.22SHADRACH 68 UNIT 332H - 332H 3.99 0.12 14.07 7.68 0.83 0.18 0.00 11.38 1.98 1.82 0.00P-DP 50.00SHADRACH MOSES CANTALOUPE 221H - 221H 2.53 0.08 253.59 172.30 120.89 0.00 0.00 0.00 340.92 87.33 0.00P-DP 35.39SHANNON 210470 3C - 3C 0.00 0.00 260.01 176.25 123.96 0.00 0.00 0.00 349.56 89.55 0.00P-DP 35.73SHANNON 210470 4B - 4B 0.00 0.00 239.65 162.93 114.25 0.00 0.00 0.00 322.18 82.53 0.00P-DP 34.76SHANNON 211271 1B - 1B 0.00 0.00 243.81 165.48 116.23 0.00 0.00 0.00 327.78 83.97 0.00P-DP 35.00SHANNON 211271 2A - 2A 0.00 0.00 12.43 7.37 2.82 0.00 0.00 0.00 10.36 1.26 0.00P-DP 14.13SHINABERRY MILDRED K 1 - 1 3.33 0.20 28.93 14.65 0.36 0.49 0.00 32.94 1.22 7.61 0.00P-DP 50.00SHIRLEY -B- 3815R - 3815R 2.38 0.08 19.49 9.37 0.21 0.34 0.00 22.41 0.73 5.08 0.00P-DP 42.37SHIRLEY 3806 - 3806 1.43 0.05 6.52 3.30 0.12 0.11 0.00 7.13 0.40 1.79 0.00P-DP 29.36SHIRLEY 3807 - 3807 0.78 0.03 10.80 5.19 0.23 0.17 0.00 11.48 0.80 3.05 0.00P-DP 50.00SHIRLEY 3808 - 3808 1.56 0.05 0.04 0.02 0.00 0.00 0.00 0.04 0.01 0.01 0.00P-DP 50.00SHOSHONE A 34-166-165 5201H - 5201H 0.00 0.00 253.53 192.01 120.87 0.00 0.00 0.00 340.85 87.32 0.00P-DP 19.91SIDWELL SE WHL BL 10H - 10H 0.00 0.00 265.82 198.23 126.73 0.00 0.00 0.00 357.37 91.55 0.00P-DP 21.11SIDWELL SE WHL BL 8H - 8H 0.00 0.00 29.58 15.92 14.10 0.00 0.00 0.00 39.77 10.19 0.00P-DP 26.91SIDWELL SW WHL BL 4H - 4H 0.00 0.00 0.74 0.40 0.01 0.01 0.00 0.76 0.03 0.11 0.00P-DP 29.67SIXTEEN PENNY NAIL 310 1LL - 1LL 0.06 0.00 0.35 0.21 0.00 0.01 0.00 0.37 0.01 0.05 0.00P-DP 21.53SIXTEEN PENNY NAIL 310 2LM - 2LM 0.02 0.00 1.96 1.20 0.07 0.03 0.00 1.66 0.23 0.31 0.00P-DP 37.45SIXTEEN PENNY NAIL 310 8JM - 8JM 0.38 0.01 0.77 0.44 0.01 0.01 0.00 0.79 0.04 0.12 0.00P-DP 29.13SIXTEEN PENNY NAIL 310A 3LL - 3LL 0.06 0.00 0.82 0.51 0.04 0.01 0.00 0.62 0.13 0.13 0.00P-DP 28.27SIXTEEN PENNY NAIL 310A 9JM - 9JM 0.21 0.01 1.00 0.61 0.06 0.01 0.00 0.69 0.18 0.16 0.00P-DP 30.41SIXTEEN PENNY NAIL 310B 10JM - 10JM 0.30 0.01 0.93 0.58 0.06 0.01 0.00 0.57 0.19 0.16 0.00P-DP 22.84SIXTEEN PENNY NAIL 310B 4LM - 4LM 0.33 0.01 0.63 0.41 0.00 0.01 0.00 0.69 0.01 0.09 0.00P-DP 23.22SIXTEEN PENNY NAIL 310B 5LL - 5LL 0.02 0.00 1.14 0.72 0.03 0.02 0.00 1.07 0.09 0.18 0.00P-DP 30.55SIXTEEN PENNY NAIL 310C 11JM - 11JM 0.16 0.00 0.72 0.44 0.04 0.01 0.00 0.50 0.13 0.12 0.00P-DP 23.22SIXTEEN PENNY NAIL 310C 6LM - 6LM 0.22 0.01 0.37 0.24 0.02 0.00 0.00 0.25 0.07 0.06 0.00P-DP 16.34SIXTEEN PENNY NAIL 310C 7LL - 7LL 0.11 0.00 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 0.76 0.56 0.36 0.00 0.00 0.00 1.02 0.26 0.00P-DP 17.68SMASHOSAURUS 1 - 1 0.00 0.00 1.43 1.01 0.68 0.00 0.00 0.00 1.92 0.49 0.00P-DP 25.07SMASHOSAURUS 3 - 3 0.00 0.00 85.26 61.03 40.65 0.00 0.00 0.00 114.62 29.36 0.00P-DP 22.16SMASHOSAURUS 5 - 5 0.00 0.00 2.32 1.64 1.11 0.00 0.00 0.00 3.12 0.80 0.00P-DP 25.45SMASHOSAURUS 7 - 7 0.00 0.00 17.72 11.17 2.07 0.15 0.00 9.85 7.47 3.94 0.00P-DP 29.39SPIRE 226-34 UNIT 1H - 1H 4.34 0.14 0.47 0.33 0.23 0.00 0.00 0.00 0.64 0.16 0.00P-DP 15.92SPITFIRE 1H - 1H 0.00 0.00 0.38 0.27 0.18 0.00 0.00 0.00 0.51 0.13 0.00P-DP 14.45SPITFIRE 3H - 3H 0.00 0.00 2.80 1.49 0.19 0.04 0.00 2.30 0.68 0.57 0.00P-DP 43.89SRO 551 ALLOC B 101H - 101H 0.40 0.01 2.02 1.02 0.15 0.02 0.00 1.59 0.53 0.42 0.00P-DP 43.21SRO 551 ALLOC. A 100H - 100H 0.31 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00STATE EILAND 3-33 11H - 11H 0.00 0.00 24.99 15.73 0.96 0.38 0.00 24.42 3.45 4.87 0.00P-DP 34.04STATE EILAND 6047B-34 51H - 51H 2.00 0.07 15.84 8.44 1.67 0.14 0.00 9.35 3.97 2.56 0.00P-DP 31.17STATE MUDDY WATERS 30 2H - 2H 5.07 0.16 2.31 1.18 0.12 0.03 0.00 2.07 0.45 0.46 0.00P-DP 37.22STELLA STATE 34-208 WRD UNIT 2H - 2H 0.26 0.01 27.53 15.51 2.42 0.30 0.00 19.60 8.72 5.85 0.00P-DP 46.15STICKLINE 1H - 1H 5.06 0.17 47.02 29.24 0.45 0.71 0.00 46.47 1.46 3.91 0.00P-DP 37.88STONE-GIST W45A 1H - 1H 3.00 0.14 47.20 30.01 0.86 0.66 0.00 42.93 2.79 4.27 0.00P-DP 37.24STONE-GIST W45B 2H - 2H 5.75 0.26 72.85 43.59 1.63 0.97 0.00 63.48 5.30 6.84 0.00P-DP 49.94STONE-GIST W45C 3H - 3H 10.91 0.50 36.18 21.66 0.65 0.50 0.00 32.94 2.13 3.27 0.00P-DP 32.17STONE-GIST W45I 9H - 9H 4.38 0.20 48.25 31.39 0.97 0.66 0.00 43.07 3.14 4.44 0.00P-DP 36.87STONE-GIST W45J 10H - 10H 6.47 0.30 26.65 13.57 0.78 0.39 0.00 25.40 1.85 2.96 0.00P-DP 38.45SUGARLOAF 74 1H - 1H 2.36 0.07 16.68 9.82 0.87 0.22 0.00 14.09 2.07 2.11 0.00P-DP 32.43SUGARLOAF 7475 1U B 1H - B 1H 2.64 0.08 11.62 6.66 0.46 0.16 0.00 10.49 1.10 1.37 0.00P-DP 48.40SUGARLOAF 7475 2U B 2H - B 2H 1.40 0.04 26.82 15.22 1.23 0.36 0.00 23.45 2.92 3.28 0.00P-DP 39.51SUGARLOAF 7475 3U A 3H - A 3H 3.73 0.11 152.01 89.74 15.76 1.17 0.00 74.97 43.81 16.37 0.00P-DP 33.88SUGG A 141-140 (ALLOC-A) 1SM - 1SM 49.59 2.38 103.17 62.16 10.57 0.81 0.00 51.61 29.39 11.09 0.00P-DP 31.97SUGG A 141-140 (ALLOC-B) 2SU - 2SU 33.26 1.60 166.61 95.17 18.93 1.14 0.00 72.61 52.63 18.21 0.00P-DP 39.65SUGG A 141-140 (ALLOC-C) 3SM - 3SM 59.58 2.86 94.55 54.02 12.31 0.50 0.00 32.15 34.23 10.58 0.00P-DP 32.68SUGG A 141-140 (ALLOC-D) 4SU - 4SU 38.75 1.86 122.04 73.42 15.92 0.65 0.00 41.36 44.25 13.66 0.00P-DP 30.14SUGG A 141-140 (ALLOC-E) 5RM - 5RM 50.09 2.41 64.22 37.28 9.52 0.24 0.00 15.18 26.46 7.37 0.00P-DP 28.77SUGG A 141-140 (ALLOC-F) 6SM - 6SM 29.95 1.44 58.05 38.30 8.97 0.18 0.00 11.62 24.93 6.72 0.00P-DP 24.20SUGG A 141-140 (ALLOC-F) 6SU - 6SU 28.22 1.36 99.88 57.03 15.28 0.33 0.00 20.89 42.46 11.54 0.00P-DP 33.33SUGG A 141-140 (ALLOC-G) 7SM - 7SM 48.07 2.31 91.81 54.44 14.73 0.24 0.00 15.22 40.95 10.72 0.00P-DP 31.54SUGG A 141-140 (ALLOC-G) 7SU - 7SU 46.36 2.23 180.85 99.82 30.71 0.32 0.00 20.25 85.37 21.39 0.00P-DP 40.33SUGG A 141-140 (ALLOC-H) 8SM - 8SM 96.63 4.64 53.25 33.49 7.64 0.22 0.00 14.04 21.24 6.07 0.00P-DP 24.88SUGG A 141-140 (ALLOC-H) 8SU - 8SU 24.04 1.15 26.25 13.82 0.42 0.39 0.00 26.01 1.42 2.15 0.00P-DP 26.74SUSTR UNIT 1H - 1H 0.97 0.04 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 569.17 400.34 221.30 0.00 0.00 0.00 736.95 167.77 0.00P-DP 19.97TANNER WYN JF 2H - 2H 0.00 0.00 1,025.93 678.25 398.90 0.00 0.00 0.00 1,328.33 302.41 0.00P-DP 27.67TANNER WYN JF 4H - 4H 0.00 0.00 44.58 26.07 0.43 0.69 0.00 45.59 1.45 3.45 0.00P-DP 22.31TARGAC UNIT 1H - 1H 0.99 0.05 3.55 2.07 0.04 0.06 0.00 3.99 0.14 0.66 0.00P-DP 30.46TEEWINOT NORTH UNIT 4LA - 4LA 0.08 0.00 9.43 5.18 0.15 0.16 0.00 10.34 0.54 1.76 0.00P-DP 42.65TEEWINOT SOUTH UNIT 5LA - 5LA 0.31 0.01 4.32 3.17 1.68 0.00 0.00 0.00 5.59 1.27 0.00P-DP 21.97THOMPSON E SMF JF 5H - 5H 0.00 0.00 67.82 49.52 26.37 0.00 0.00 0.00 87.81 19.99 0.00P-DP 23.42THOMPSON W SMF JF 1H - 1H 0.00 0.00 65.23 47.33 25.36 0.00 0.00 0.00 84.45 19.23 0.00P-DP 23.36THOMPSON W SMF JF 3H - 3H 0.00 0.00 0.09 0.07 0.00 0.00 0.00 0.10 0.01 0.02 0.00P-DP 8.26THORPE 1-74 LOV 2H - 2H 0.01 0.00 0.51 0.29 0.01 0.01 0.00 0.55 0.03 0.11 0.00P-DP 28.57THORPE 1-74 LOV 3H - 3H 0.04 0.00 0.89 0.45 0.02 0.01 0.00 0.95 0.06 0.18 0.00P-DP 30.90THORPE 1-74 LOV 4H - 4H 0.07 0.00 23.23 13.18 1.87 0.25 0.00 16.45 4.46 3.38 0.00P-DP 38.87THURMOND 132 ALLOC C 11H - 11H 5.70 0.18 24.93 13.55 1.56 0.31 0.00 19.81 3.71 3.33 0.00P-DP 41.10THURMOND A137 ALLOC. A 10H - 10H 4.74 0.15 15.75 10.32 7.51 0.00 0.00 0.00 21.18 5.42 0.00P-DP 23.61TIGER 210187 2A - 2A 0.00 0.00 9.85 7.10 4.69 0.00 0.00 0.00 13.24 3.39 0.00P-DP 15.80TIGER 210187 3C - 3C 0.00 0.00 9.33 6.82 4.45 0.00 0.00 0.00 12.54 3.21 0.00P-DP 14.48TIGER 210187 5B - 5B 0.00 0.00 0.03 0.02 0.02 0.00 0.00 0.00 0.05 0.02 0.00P-DP 50.00TIGER 210475 4C - 4C 0.00 0.00 15.06 9.76 7.18 0.00 0.00 0.00 20.25 5.19 0.00P-DP 23.72TIGER 210476 1A - 1A 0.00 0.00 0.42 0.27 0.01 0.01 0.00 0.46 0.02 0.11 0.00P-DP 33.07TIMMERMAN J1 2208MH - 2208MH 0.05 0.00 0.73 0.45 0.01 0.01 0.00 0.77 0.05 0.18 0.00P-DP 39.98TIMMERMAN J10 2206LH - 2206LH 0.09 0.00 0.76 0.43 0.03 0.01 0.00 0.69 0.09 0.20 0.00P-DP 39.79TIMMERMAN J11 2206BH - 2206BH 0.18 0.01 0.51 0.32 0.01 0.01 0.00 0.54 0.04 0.13 0.00P-DP 35.92TIMMERMAN J2 2208LH - 2208LH 0.07 0.00 0.51 0.31 0.02 0.01 0.00 0.46 0.06 0.14 0.00P-DP 38.96TIMMERMAN J3 2208BH - 2208BH 0.12 0.00 0.81 0.51 0.02 0.01 0.00 0.79 0.07 0.21 0.00P-DP 39.89TIMMERMAN J4 2207MH - 2207MH 0.14 0.01 0.55 0.36 0.02 0.01 0.00 0.53 0.06 0.14 0.00P-DP 35.44TIMMERMAN J5 2207LH - 2207LH 0.11 0.00 0.42 0.26 0.02 0.01 0.00 0.36 0.06 0.11 0.00P-DP 33.80TIMMERMAN J6 2207BH - 2207BH 0.11 0.00 0.50 0.31 0.01 0.01 0.00 0.48 0.05 0.13 0.00P-DP 35.79TIMMERMAN J7 2217LH - 2217LH 0.10 0.00 0.38 0.24 0.02 0.00 0.00 0.27 0.07 0.11 0.00P-DP 32.57TIMMERMAN J8 2207CH - 2207CH 0.14 0.01 0.88 0.58 0.02 0.01 0.00 0.90 0.07 0.22 0.00P-DP 39.62TIMMERMAN J9 2206MH - 2206MH 0.14 0.00 9.37 4.79 0.47 0.12 0.00 8.01 1.11 1.17 0.00P-DP 49.03TIN STAR A L 33H - L 33H 1.42 0.04 3.33 1.81 0.23 0.04 0.00 2.55 0.54 0.46 0.00P-DP 38.20TIN STAR B L 42H - L 42H 0.69 0.02 5.23 3.03 0.36 0.06 0.00 3.99 0.86 0.72 0.00P-DP 39.76TIN STAR D U 46H - U 46H 1.10 0.03 0.01 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.00P-DP 29.33TIPI CHAPMAN 34-163 1H - 1H 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.00P-DP 30.57TIPI CHAPMAN 34-163 2H - 2H 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 22.91TIPI CHAPMAN 34-163 3H - 3H 0.00 0.00 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 0.02 0.01 0.00 0.00 0.00 0.02 0.00 0.00 0.00P-DP 33.94TIPI CHAPMAN 34-163 4H - 4H 0.00 0.00 4.66 2.72 0.11 0.07 0.00 4.49 0.33 0.72 0.00P-DP 30.51TITO'S 31-42 1LS - 1LS 0.55 0.01 4.70 2.75 0.09 0.07 0.00 4.66 0.28 0.72 0.00P-DP 30.55TITO'S 31-42 1WA - 1WA 0.47 0.01 4.20 2.48 0.08 0.06 0.00 4.21 0.23 0.64 0.00P-DP 29.23TITO'S 31-42 1WB - 1WB 0.39 0.01 7.00 4.57 0.08 0.11 0.00 7.36 0.26 1.05 0.00P-DP 31.00TITO'S 31-42 2LS - 2LS 0.43 0.01 6.45 4.00 0.57 0.04 0.00 2.80 1.78 1.11 0.00P-DP 28.74TITO'S 31-42 2WA - 2WA 2.98 0.08 6.22 3.91 0.09 0.10 0.00 6.38 0.29 0.94 0.00P-DP 31.72TITO'S 31-42 2WB - 2WB 0.49 0.01 7.87 4.56 0.04 0.13 0.00 8.74 0.11 1.17 0.00P-DP 36.25TITO'S 31-42 3WA - 3WA 0.18 0.00 17.87 9.73 1.30 0.20 0.00 13.02 3.09 2.19 0.00P-DP 47.93TOWNSEN 1 - 2H 3.95 0.12 1.56 0.85 0.02 0.03 0.00 1.75 0.07 0.29 0.00P-DP 31.69TRAUBE 1-11 WRD 1H - 1H 0.04 0.00 1.62 0.84 0.05 0.03 0.00 1.65 0.17 0.31 0.00P-DP 33.43TRAUBE 1-11 WRD 2H - 2H 0.10 0.00 4.94 2.53 0.20 0.06 0.00 4.01 0.69 0.63 0.00P-DP 31.51TREE FROG 47 EAST A 1LS - 1LS 0.87 0.04 12.82 7.61 0.22 0.19 0.00 12.50 0.76 1.39 0.00P-DP 36.99TREE FROG 47 EAST A 1WA - 1WA 0.96 0.04 5.22 2.83 0.18 0.07 0.00 4.45 0.62 0.64 0.00P-DP 29.92TREE FROG 47 EAST C 3LS - 3LS 0.78 0.04 22.99 14.27 0.63 0.32 0.00 20.83 2.14 2.68 0.00P-DP 42.76TREE FROG 47 EAST C 3WA - 3WA 2.70 0.12 6.77 3.58 0.18 0.09 0.00 6.15 0.62 0.79 0.00P-DP 32.95TREE FROG 47 EAST C 3WB - 3WB 0.78 0.04 75.72 48.58 1.60 1.09 0.00 71.93 5.42 8.45 0.00P-DP 48.11TREE FROG 47 WEST UNIT #7MS 6.83 0.31 11.84 6.99 0.26 0.17 0.00 11.21 0.87 1.33 0.00P-DP 36.12TREE FROG 47 WEST UNIT 5LS - 5LS 1.09 0.05 17.11 10.23 0.34 0.25 0.00 16.42 1.14 1.89 0.00P-DP 39.84TREE FROG 47 WEST UNIT 5WA - 5WA 1.44 0.07 14.59 8.64 0.31 0.21 0.00 13.86 1.04 1.63 0.00P-DP 38.31TREE FROG 47 WEST UNIT 5WB - 5WB 1.31 0.06 52.88 33.74 1.02 0.77 0.00 50.87 3.47 5.83 0.00P-DP 44.31TREE FROG 47 WEST UNIT 7LS - 7LS 4.37 0.20 38.79 24.54 1.56 0.48 0.00 31.76 5.29 4.92 0.00P-DP 40.80TREE FROG 47 WEST UNIT 7WA - 7WA 6.67 0.31 4.03 2.32 0.21 0.05 0.00 3.40 0.50 0.51 0.00P-DP 25.83TRIANGLE 75 2H - 2H 0.64 0.02 1.46 0.77 0.09 0.02 0.00 1.27 0.31 0.30 0.00P-DP 39.20TRIDACNA 34-208 WRD UNIT 1H - 1H 0.18 0.01 0.96 0.55 0.07 0.01 0.00 0.74 0.26 0.20 0.00P-DP 33.91TRIDACNA 34-208 WRD UNIT 2H - 2H 0.15 0.01 1.14 0.66 0.06 0.02 0.00 1.02 0.22 0.23 0.00P-DP 34.68TRIDACNA 34-208 WRD UNIT 3H - 3H 0.13 0.00 0.35 0.22 0.02 0.00 0.00 0.28 0.09 0.07 0.00P-DP 22.09TROTT 34-183 1H - 1H 0.05 0.00 0.44 0.27 0.01 0.01 0.00 0.47 0.03 0.08 0.00P-DP 40.70TUMBLEWEED 34-170 UNIT 1H - 1H 0.02 0.00 0.94 0.54 0.02 0.02 0.00 1.02 0.06 0.18 0.00P-DP 26.52UNDERWOOD 34-138 UNIT 1H - 1H 0.04 0.00 25.39 17.68 12.11 0.00 0.00 0.00 34.14 8.75 0.00P-DP 16.42VALERIE 210473 1A - 1A 0.00 0.00 26.30 18.06 12.54 0.00 0.00 0.00 35.36 9.06 0.00P-DP 17.13VALERIE 210473 2B - 2B 0.00 0.00 38.92 24.45 18.56 0.00 0.00 0.00 52.33 13.40 0.00P-DP 23.67VALERIE 210473 4C - 4C 0.00 0.00 1.08 0.66 0.04 0.02 0.00 1.05 0.15 0.21 0.00P-DP 20.71VICKERS '34-127' 1H - 1H 0.09 0.00 1.23 0.77 0.02 0.02 0.00 1.34 0.07 0.23 0.00P-DP 19.61VICKERS '34-127' 2H - 2H 0.04 0.00 16.20 10.19 0.27 0.24 0.00 15.90 0.91 1.75 0.00P-DP 32.70WARD 18CC 1804D - 1804D 1.15 0.05 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 13.82 8.42 0.11 0.22 0.00 14.35 0.39 1.40 0.00P-DP 32.00WARD 18D 1803D - 1803D 0.49 0.02 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00WARREN DUNLAP 1 - 1 0.00 0.00 1.45 0.81 0.01 0.03 0.00 1.68 0.02 0.26 0.00P-DP 29.88WHIRLAWAY 99 1HA - 1HA 0.01 0.00 0.16 0.09 0.00 0.00 0.00 0.18 0.01 0.03 0.00P-DP 46.17WHISKEY RIVER 9596A-34 11H - 11H 0.00 0.00 0.03 0.02 0.00 0.00 0.00 0.03 0.00 0.01 0.00P-DP 26.47WHISKEY RIVER 9596A-34 12H - 12H 0.00 0.00 0.02 0.01 0.00 0.00 0.00 0.02 0.00 0.00 0.00P-DP 21.03WHISKEY RIVER 9596A-34 13H - 13H 0.00 0.00 0.08 0.04 0.00 0.00 0.00 0.09 0.00 0.01 0.00P-DP 37.95WHISKEY RIVER 9596B-34 1H - 1H 0.00 0.00 0.05 0.03 0.00 0.00 0.00 0.06 0.00 0.01 0.00P-DP 31.86WHISKEY RIVER 9596B-34 31H - 31H 0.00 0.00 0.07 0.04 0.00 0.00 0.00 0.07 0.01 0.01 0.00P-DP 34.35WHISKEY RIVER 9596B-34 32H - 32H 0.01 0.00 0.14 0.07 0.00 0.00 0.00 0.16 0.01 0.03 0.00P-DP 48.76WHISKEY RIVER 9596C-34 1H - 1H 0.00 0.00 0.11 0.06 0.00 0.00 0.00 0.12 0.01 0.02 0.00P-DP 44.08WHISKEY RIVER 9596D-34 81H - 81H 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00WHITLEY 34-231 1H - 1H 0.00 0.00 40.30 23.80 2.98 0.46 0.00 29.83 7.09 5.68 0.00P-DP 34.97WILLETT POT STILL 5-2C UNIT 1H - 1H 9.06 0.28 13.18 8.26 0.39 0.18 0.00 11.96 1.23 2.05 0.00P-DP 46.59WILLIE THE WILDCAT 3-15 A 2.05 0.05 7.77 4.85 0.20 0.11 0.00 7.33 0.61 1.20 0.00P-DP 40.70WILLIE THE WILDCAT 3-15 A 1.03 0.03 6.68 4.19 0.17 0.10 0.00 6.33 0.51 1.03 0.00P-DP 38.84WILLIE THE WILDCAT 3-15 A 0.86 0.02 10.49 6.53 0.27 0.15 0.00 9.89 0.83 1.62 0.00P-DP 44.11WILLIE THE WILDCAT 3-15 B 1.39 0.04 10.53 6.50 0.23 0.16 0.00 10.24 0.71 1.61 0.00P-DP 44.37WILLIE THE WILDCAT 3-15 B 1.19 0.03 9.74 6.06 0.23 0.14 0.00 9.31 0.72 1.50 0.00P-DP 43.29WILLIE THE WILDCAT 3-15 B 1.21 0.03 13.89 8.65 0.51 0.18 0.00 11.82 1.59 2.19 0.00P-DP 47.34WILLIE THE WILDCAT 3-15 B 2WB - 2WB 2.67 0.07 10.60 6.60 0.35 0.14 0.00 9.38 1.08 1.66 0.00P-DP 44.22WILLIE THE WILDCAT 3-15 C 1.80 0.05 6.99 4.37 0.19 0.10 0.00 6.52 0.58 1.08 0.00P-DP 39.46WILLIE THE WILDCAT 3-15 C 0.97 0.02 10.70 6.76 0.31 0.15 0.00 9.82 0.95 1.66 0.00P-DP 43.98WILLIE THE WILDCAT 3-15 D 1.59 0.04 8.63 5.42 0.30 0.11 0.00 7.49 0.93 1.36 0.00P-DP 41.69WILLIE THE WILDCAT 3-15 D 1.56 0.04 5.23 3.24 0.12 0.08 0.00 5.06 0.36 0.80 0.00P-DP 36.43WILLIE THE WILDCAT 3-15 D 5JD - 5JD 0.61 0.02 8.20 5.15 0.19 0.12 0.00 7.84 0.61 1.26 0.00P-DP 39.52WILLIE THE WILDCAT 3-15 D 6LS - 6LS 1.01 0.03 18.18 11.45 0.44 0.26 0.00 17.33 1.36 2.80 0.00P-DP 50.00WILLIE THE WILDCAT 3-15 E 2.28 0.06 6.95 4.44 0.20 0.10 0.00 6.35 0.63 1.08 0.00P-DP 38.86WILLIE THE WILDCAT 3-15 E 1.05 0.03 1.01 0.73 0.01 0.02 0.00 1.05 0.04 0.15 0.00P-DP 17.28WILLIE THE WILDCAT 3-15 E 0.07 0.00 2.02 1.06 0.06 0.03 0.00 1.91 0.22 0.53 0.00P-DP 35.19WILLOW LAKES 19 191H - 191H 0.42 0.01 5.81 3.29 0.50 0.06 0.00 4.21 1.79 1.23 0.00P-DP 46.73WILSON 184-185 UNIT 2H - 2H 1.04 0.03 2.37 1.43 0.16 0.03 0.00 1.84 0.37 0.32 0.00P-DP 35.15WINDY MOUNTAIN 7879 1U B 1H - B 1H 0.47 0.01 3.58 1.88 0.22 0.04 0.00 2.89 0.51 0.47 0.00P-DP 43.47WINDY MOUNTAIN 7879 2U B 2H - B 2H 0.66 0.02 0.64 0.35 0.01 0.01 0.00 0.69 0.04 0.12 0.00P-DP 27.44WRIGHT 1-22 E WRD UNIT 2H - 2H 0.03 0.00 0.70 0.37 0.02 0.01 0.00 0.75 0.05 0.13 0.00P-DP 28.86WRIGHT 1-22 W WRD UNIT 2H - 2H 0.03 0.00 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 0.38 0.22 0.01 0.01 0.00 0.39 0.04 0.07 0.00P-DP 21.60WRIGHT 1-22E WRD 1H - 1H 0.02 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.70WRIGHT 1-22W WRD 1H - 1H 0.00 0.00 17.89 10.19 0.61 0.23 0.00 14.86 1.88 1.87 0.00P-DP 47.22XBC-CAROLINE 3B 302H - 302H 3.02 0.15 12.41 7.31 0.43 0.16 0.00 10.31 1.30 1.30 0.00P-DP 42.25XBC-CAROLINE 3C 303H - 303H 2.09 0.10 14.33 8.38 0.50 0.18 0.00 11.83 1.54 1.50 0.00P-DP 43.91XBC-CAROLINE 3K 311H - 311H 2.46 0.12 14.38 8.38 0.43 0.19 0.00 12.40 1.32 1.45 0.00P-DP 43.84XBC-CAROLINE 3L 312H - 312H 2.11 0.10 14.06 8.31 0.41 0.19 0.00 12.17 1.26 1.41 0.00P-DP 43.27XBC-CAROLINE 3M 313H - 313H 2.03 0.10 19.00 10.42 0.43 0.26 0.00 17.33 1.33 1.80 0.00P-DP 48.30XBC-UNRUH 3A 16H - 16H 2.14 0.10 14.85 8.74 0.66 0.17 0.00 11.25 2.03 1.68 0.00P-DP 43.26XBC-UNRUH 3B 17H - 17H 3.25 0.16 0.04 0.02 0.02 0.00 0.00 0.00 0.06 0.02 0.00P-DP 46.29YANKEE 210475 5A - 5A 0.00 0.00 1.73 1.13 0.03 0.03 0.00 1.94 0.09 0.36 0.00P-DP 30.89YELLOW ROSE A UNIT 1H - 1H 0.06 0.00 2.65 1.56 0.04 0.05 0.00 2.97 0.14 0.55 0.00P-DP 39.08YELLOW ROSE A UNIT 2H - 2H 0.10 0.00 1.32 0.85 0.02 0.02 0.00 1.45 0.08 0.28 0.00P-DP 29.40YELLOW ROSE A UNIT 3H - 3H 0.06 0.00 3.06 1.79 0.07 0.05 0.00 3.31 0.23 0.64 0.00P-DP 41.04YELLOW ROSE B UNIT 1H - 1H 0.16 0.01 1.22 0.76 0.00 0.02 0.00 1.46 0.01 0.25 0.00P-DP 29.29YELLOW ROSE B UNIT 2H - 2H 0.00 0.00 4.15 2.73 0.12 0.07 0.00 4.34 0.41 0.88 0.00P-DP 40.05YELLOW ROSE B UNIT 3H - 3H 0.28 0.01 155.18 36,295.50 55,826.52 0.00 14,516.00 0.00 53,131.02 10,141.33 16,586.32Total 50.00 7,070.17 278.18 Proved Behind Pipe Rsv Class & Category 36.36 23.83 0.96 0.54 0.00 36.04 3.29 9.38 0.00P-BP 40.94HALL-PORTER 'C' 621-596 231 - 231 6.41 0.22 54.83 32.63 1.89 0.75 0.00 50.22 6.49 14.53 0.00P-BP 48.82HALL-PORTER `B` 621-596 #123 12.65 0.44 32.50 18.41 1.76 0.42 0.00 27.11 4.19 4.15 0.00P-BP 50.00KODIAK 7677 1U B 1H - B 1H 5.35 0.16 32.89 18.56 1.78 0.43 0.00 27.44 4.24 4.20 0.00P-BP 50.00KODIAK 7677 2U B 2H - B 2H 5.42 0.17 32.55 18.40 1.81 0.42 0.00 26.94 4.30 4.19 0.00P-BP 50.00KODIAK 7677 3U A 3H - A 3H 5.50 0.17 32.30 18.18 1.79 0.41 0.00 26.73 4.27 4.16 0.00P-BP 50.00KODIAK 7677 4U A 4H - A 4H 5.45 0.17 6.37 4.00 0.37 0.08 0.00 5.49 1.33 1.22 0.00P-BP 49.31MARY GRACE 201-202 UNIT 2H - 2H 0.77 0.03 38.32 20.35 1.19 0.64 0.00 41.50 4.29 7.54 0.00P-BP 50.00Mud Hen 5 0.06 0.00 166.54 100.56 5.41 2.25 0.00 147.60 16.82 26.03 0.00P-BP 48.36NORRIS UNIT 32-H #3332SH 28.15 0.71 169.08 102.47 5.49 2.29 0.00 149.84 17.08 26.43 0.00P-BP 48.50NORRIS UNIT 32-H #3333SH 28.58 0.72 191.74 115.15 6.23 2.59 0.00 169.90 19.38 29.97 0.00P-BP 50.00NORRIS-MIMS ALLOCATION #3335SH 32.43 0.82 23.86 15.11 0.50 0.36 0.00 23.36 1.55 3.65 0.00P-BP 45.05TITOS 31-42 #U 1WB 2.60 0.07 75.67 45.91 1.85 1.06 0.00 70.12 6.28 8.65 0.00P-BP 49.04TREE FROG 47 WEST UNIT #7WB 7.91 0.36 12.25 533.57 893.00 0.00 144.11 0.00 93.52 802.29 31.04Total 50.00 141.29 4.05 Proved Shut-In Rsv Class & Category 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00ALLMAN 24 6H - 6H 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00AVARY 1 - 1 0.00 0.00 TABLE 8

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2022 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00AVARY 10 - 10 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00AVARY 11 - 11 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00AVARY 12 - 12 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00AVARY 14 - 14 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00AVARY 15 - 15 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00AVARY 16 - 16 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00AVARY 17 - 17 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00AVARY 2 - 2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00AVARY 3 - 3 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00AVARY 4 - 4 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00AVARY 5 - 5 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00AVARY 6 - 6 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00AVARY 7 - 7 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00AVARY 8 - 8 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00AVARY 9 - 9 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00AVARY, G. Q. 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00AVARY, G. Q. 2 - 2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00BLACK STONE 34-216 1H - 1H 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00BRUNSON '15' 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00BYRD 34-170 UNIT 1H - 1H 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00BYRD 34-170 UNIT 2H - 2H 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00GATLIN, MARY 2006H - 2006H 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00HA RA SUA;WIGGINS 36-15-10 H 001 - 001 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00HERMOSA 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00HERMOSA UNIT 2 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00HOLY GRAIL 43 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00JANAK UNIT 1H - 1H 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00LANE, ROWENA 11D - 11D 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00LANE, ROWENA 11D - 11D 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00NORTH AMERICAN COAL 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00NORTH AMERICAN COAL 1-3 - 1-3 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00PARKS FIELD UNIT NO. 2 1929 - 1929 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00PARKS FIELD UNIT NO. 2 904H - 904H 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-SI 0.00PARTAGAS 37 1 - 1 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.00P-SI 22.65QUITO, S. W. (DELAWARE) UNIT 702 - 702 0.00 0.00 TABLE 8

Gross Ultimates, Interests, & Prices

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA Proved Producing Rsv Class & Category ABIGAIL 218-219 UNIT 1H P-DP 0.0000000 0.0001208 0.0001208 0.0000000 3,936.80 313.93 3.60 65.04 136.33 1,942.96 0 ACKERLY BROWN 9 1 P-DP 0.0000000 0.0006510 0.0006510 0.0000000 178.21 142.39 3.11 65.50 108.88 139.38 0 ADAMEK UNIT 1H P-DP 0.0000000 0.0105000 0.0105000 0.0000000 114.93 67.10 3.58 65.06 30.37 114.93 0 ADAMEK UNIT 2H P-DP 0.0000000 0.0105000 0.0105000 0.0000000 1,846.88 139.74 3.58 65.06 105.34 1,283.38 0 ADMIRAL 4-48 47 1H P-DP 0.0000000 0.0076761 0.0076761 0.0000000 3,708.96 665.31 2.38 64.55 416.22 2,445.39 0 ALEX & PAULINE TAMSULA 1 P-DP 0.0000000 0.1100000 0.1100000 0.0000000 56.64 0.00 2.75 64.56 0.00 56.64 0 ALEX TAMSULA 2 P-DP 0.0000000 0.1100000 0.1100000 0.0000000 90.26 0.00 2.75 64.56 0.00 66.55 0 ALEX TAMSULA 3 P-DP 0.0000000 0.1003470 0.1003470 0.0000000 65.87 0.09 2.75 64.56 0.09 65.87 0 ALEX TAMSULA 4 P-DP 0.0000000 0.1100000 0.1100000 0.0000000 28.37 0.00 2.75 64.56 0.00 28.37 0 ALLMAN 24 1H P-DP 0.0000000 0.0043022 0.0043022 0.0000000 5,780.67 260.38 2.38 64.55 194.31 4,068.19 0 ALLRED UNIT B 08-05 5AH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 909.02 762.07 3.39 66.02 524.75 651.22 0 ALLRED UNIT B 08-05 5BH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 1,188.11 267.05 3.39 66.02 189.92 413.07 0 ALLRED UNIT B 08-05 5MH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 802.03 294.76 3.39 66.02 80.63 86.57 0 ALLRED UNIT B 08-05 5SH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 599.00 308.10 3.39 66.02 75.97 71.27 0 ALLRED UNIT B 08-05 6AH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 786.16 533.65 3.39 66.02 119.63 93.76 0 ALLRED UNIT B 08-05 6MH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 366.29 407.94 3.39 66.02 76.28 61.23 0 ALLRED UNIT B 08-05 6SH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 769.55 359.93 3.39 66.02 65.29 122.41 0 ALLRED UNIT B 08-05 7AH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 795.45 322.42 3.39 66.02 86.88 104.60 0 ALLRED UNIT B 08-05 7BH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 858.11 236.25 3.39 66.02 50.75 122.14 0 ALLRED UNIT B 08-05 8AH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 795.82 714.04 3.39 66.02 454.18 449.12 0 ALLRED UNIT B 08-05 8SH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 1,095.28 598.88 3.39 66.02 406.46 558.40 0 ALPHA 210488 1A P-DP 0.0000000 0.0003237 0.0003237 0.0000000 6,649.85 0.00 2.82 64.56 0.00 5,057.01 0 ALPHA 210488 2B P-DP 0.0000000 0.0003237 0.0003237 0.0000000 8,311.56 0.00 2.82 64.56 0.00 5,987.39 0 ALPHA 210488 3C P-DP 0.0000000 0.0003237 0.0003237 0.0000000 9,743.99 0.00 2.82 64.56 0.00 7,015.32 0 ARCHIE E WYN JF 6H P-DP 0.0000000 0.0312851 0.0312851 0.0000000 8,370.48 0.00 3.33 64.56 0.00 5,956.79 0 ARCHIE E WYN JF 8H P-DP 0.0000000 0.0312851 0.0312851 0.0000000 7,518.59 0.00 3.33 64.56 0.00 4,721.97 0 AUSTIN 5H P-DP 0.0000000 0.0060725 0.0060725 0.0000000 5,699.06 0.00 2.22 64.56 0.00 1,610.69 0 AUSTIN 6H P-DP 0.0000000 0.0060725 0.0060725 0.0000000 5,819.46 0.00 2.22 64.56 0.00 1,746.97 0 AUSTIN 7H P-DP 0.0000000 0.0060725 0.0060725 0.0000000 6,144.59 0.00 2.22 64.56 0.00 1,833.76 0 AUSTIN 8H P-DP 0.0000000 0.0060725 0.0060725 0.0000000 5,532.37 0.00 2.22 64.56 0.00 1,780.53 0 B AND B 1H P-DP 0.0000000 0.0005308 0.0005308 0.0000000 2,746.92 364.20 3.40 65.18 130.45 1,013.52 0 B AND B 2H P-DP 0.0000000 0.0005308 0.0005308 0.0000000 3,683.03 441.53 3.40 65.18 163.54 1,399.18 0 B AND B STATE 4H P-DP 0.0000000 0.0004530 0.0004530 0.0000000 2,438.81 308.89 3.40 65.18 53.75 323.11 0 B AND B STATE A 5H P-DP 0.0000000 0.0004530 0.0004530 0.0000000 2,701.15 350.90 3.40 65.18 60.11 427.98 0 BAKER TRUST 1 P-DP 0.0000000 0.0030208 0.0030208 0.0000000 27.63 26.68 3.39 66.02 22.32 27.63 0 BARSTOW -18- 1 P-DP 0.0000000 0.0000036 0.0000036 0.0000000 130.04 27.30 3.60 66.56 8.21 38.15 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA BARSTOW -18- 2 P-DP 0.0000000 0.0000036 0.0000036 0.0000000 146.36 26.92 3.60 66.56 8.04 37.58 0 BARSTOW -18- 3 P-DP 0.0000000 0.0000036 0.0000036 0.0000000 138.26 28.69 3.60 66.56 9.40 40.47 0 BARSTOW -18- 4 P-DP 0.0000000 0.0000036 0.0000036 0.0000000 119.93 17.66 3.60 66.56 7.22 38.12 0 BARSTOW -18- 5 P-DP 0.0000000 0.0000036 0.0000036 0.0000000 131.91 29.59 3.60 66.56 8.63 41.35 0 BARSTOW -23- 1 P-DP 0.0000000 0.0000039 0.0000039 0.0000000 26.45 3.56 3.60 66.56 2.92 21.39 0 BARSTOW -23- 2 P-DP 0.0000000 0.0000039 0.0000039 0.0000000 26.30 3.13 3.60 66.56 2.39 22.32 0 BARSTOW -23- 3 P-DP 0.0000000 0.0000039 0.0000039 0.0000000 851.55 132.71 3.60 65.04 33.07 204.16 0 BARSTOW -23- 4 P-DP 0.0000000 0.0000039 0.0000039 0.0000000 580.56 72.54 3.60 65.04 28.72 171.85 0 BARSTOW -23- 6 P-DP 0.0000000 0.0000039 0.0000039 0.0000000 30.85 4.09 3.60 66.56 2.78 22.49 0 BARSTOW -23- 6A P-DP 0.0000000 0.0000039 0.0000039 0.0000000 22.30 3.23 3.60 66.56 2.42 17.02 0 BARSTOW -23- 7 P-DP 0.0000000 0.0000039 0.0000039 0.0000000 29.36 4.11 3.60 66.56 2.42 21.32 0 BARSTOW -23- 8 P-DP 0.0000000 0.0000039 0.0000039 0.0000000 36.97 3.60 3.60 66.56 2.70 25.47 0 BARSTOW -23- 9 P-DP 0.0000000 0.0000039 0.0000039 0.0000000 33.67 3.23 3.60 66.56 2.57 25.21 0 BARSTOW 155 1 P-DP 0.0000000 0.0000075 0.0000075 0.0000000 38.25 51.12 3.60 65.04 11.98 11.15 0 BARSTOW 27 1 P-DP 0.0000000 0.0000050 0.0000050 0.0000000 170.07 4.94 3.60 66.56 4.15 42.03 0 BARSTOW 27 2 P-DP 0.0000000 0.0000050 0.0000050 0.0000000 176.12 7.16 3.60 66.56 6.49 41.01 0 BARSTOW 27 3 P-DP 0.0000000 0.0000050 0.0000050 0.0000000 215.21 294.10 3.60 65.04 68.23 44.56 0 BARSTOW 27 4 P-DP 0.0000000 0.0000050 0.0000050 0.0000000 177.56 5.90 3.60 66.56 4.46 43.48 0 BARSTOW 27 5 P-DP 0.0000000 0.0000050 0.0000050 0.0000000 202.13 6.46 3.60 66.56 4.69 43.87 0 BARSTOW 27 6 P-DP 0.0000000 0.0000050 0.0000050 0.0000000 182.07 6.58 3.60 66.56 6.03 43.72 0 BARSTOW 27 7 P-DP 0.0000000 0.0000050 0.0000050 0.0000000 149.55 5.46 3.60 66.56 4.41 41.53 0 BARSTOW 33 UA 1BS P-DP 0.0000000 0.0000113 0.0000113 0.0000000 1,204.52 186.02 3.60 65.04 143.87 652.96 0 BARSTOW 33 UB 2BS P-DP 0.0000000 0.0000113 0.0000113 0.0000000 1,171.77 341.18 3.60 65.04 300.73 1,039.35 0 BARSTOW 33-34 1H P-DP 0.0000000 0.0000025 0.0000025 0.0000000 1,504.07 725.80 3.60 65.04 559.04 1,133.50 0 BARSTOW 33-35 1H P-DP 0.0000000 0.0000018 0.0000018 0.0000000 585.01 296.34 3.60 65.04 291.22 576.46 0 BARSTOW 33-35 2H P-DP 0.0000000 0.0000018 0.0000018 0.0000000 766.86 336.27 3.60 65.04 244.08 509.94 0 BARSTOW 33-35 3H P-DP 0.0000000 0.0000018 0.0000018 0.0000000 3,273.18 553.21 3.60 65.04 468.85 2,066.38 0 BARSTOW A 3652H P-DP 0.0000000 0.0000003 0.0000003 0.0000000 5,561.51 1,206.04 3.60 65.04 642.88 2,454.77 0 BATES S CRC JF 5H P-DP 0.0000000 0.0802990 0.0802990 0.0000000 17,042.17 0.00 3.33 64.56 0.00 11,854.94 0 BIG JAY 10-15 A #1JD P-DP 0.0000000 0.0006176 0.0006176 0.0000000 608.85 438.31 3.11 65.50 115.32 120.57 0 BIG JAY 10-15 A #1LS P-DP 0.0000000 0.0006176 0.0006176 0.0000000 774.67 494.84 3.11 65.50 139.14 157.49 0 BIG JAY 10-15 A #1MS P-DP 0.0000000 0.0006176 0.0006176 0.0000000 227.27 243.95 3.11 65.50 52.61 39.05 0 BIG JAY 10-15 A #1WA P-DP 0.0000000 0.0006176 0.0006176 0.0000000 956.13 625.50 3.11 65.50 156.49 199.94 0 BIG JAY 10-15 B #2DN P-DP 0.0000000 0.0006176 0.0006176 0.0000000 775.65 488.79 3.11 65.50 133.64 176.72 0 BIG JAY 10-15 B #2LS P-DP 0.0000000 0.0006176 0.0006176 0.0000000 808.95 578.26 3.11 65.50 134.96 135.51 0 BIG JAY 10-15 B #2WB P-DP 0.0000000 0.0006176 0.0006176 0.0000000 1,434.33 383.15 3.11 65.50 88.02 269.98 0 BIG JAY 10-15 B #3JC P-DP 0.0000000 0.0006176 0.0006176 0.0000000 580.55 531.47 3.11 65.50 122.33 103.17 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA BIG JAY 10-15 C #4LS P-DP 0.0000000 0.0006176 0.0006176 0.0000000 766.43 598.69 3.11 65.50 155.21 141.43 0 BIG JAY 10-15 C #4MS P-DP 0.0000000 0.0006176 0.0006176 0.0000000 208.66 193.60 3.11 65.50 52.75 44.80 0 BIG JAY 10-15 C #4WA P-DP 0.0000000 0.0006176 0.0006176 0.0000000 1,645.56 626.15 3.11 65.50 160.42 278.41 0 BIG JAY 10-15 D #5JC P-DP 0.0000000 0.0006176 0.0006176 0.0000000 255.20 151.60 3.11 65.50 47.30 61.14 0 BIG JAY 10-15 D #6DN P-DP 0.0000000 0.0006176 0.0006176 0.0000000 467.66 244.46 3.11 65.50 109.06 158.18 0 BIG JAY 10-15 D #6LS P-DP 0.0000000 0.0006176 0.0006176 0.0000000 533.99 269.22 3.11 65.50 94.17 116.46 0 BIG JAY 10-15 D #6WB P-DP 0.0000000 0.0006176 0.0006176 0.0000000 997.02 264.68 3.11 65.50 84.10 233.98 0 BIG JAY 10-15 E #7JD P-DP 0.0000000 0.0006176 0.0006176 0.0000000 417.14 251.97 3.11 65.50 90.65 115.11 0 BIG JAY 10-15 E #7LS P-DP 0.0000000 0.0006176 0.0006176 0.0000000 779.61 512.39 3.11 65.50 140.37 181.21 0 BIG JAY 10-15 E #7MS P-DP 0.0000000 0.0006176 0.0006176 0.0000000 222.74 178.33 3.11 65.50 57.38 63.08 0 BIG JAY 10-15 E #7WA P-DP 0.0000000 0.0006176 0.0006176 0.0000000 811.23 456.62 3.11 65.50 149.39 225.49 0 BLACK STONE 34-216 2H P-DP 0.0000000 0.0009146 0.0009146 0.0000000 130.97 23.08 3.60 65.04 23.08 130.97 0 BOBCAT 55-1-28 UNIT 1H P-DP 0.0000000 0.0000895 0.0000895 0.0000000 4,042.89 783.82 3.40 65.18 418.17 2,116.99 0 BOENING UNIT 1H P-DP 0.0000000 0.0106684 0.0106684 0.0000000 839.99 191.40 3.58 65.06 146.06 714.89 0 BOENING UNIT 2H P-DP 0.0000000 0.0106684 0.0106684 0.0000000 1,561.35 168.03 3.58 65.06 144.54 1,002.08 0 BOENING UNIT 3H P-DP 0.0000000 0.0106684 0.0106684 0.0000000 2,005.77 277.98 3.58 65.06 173.39 1,235.49 0 BOENING UNIT 4H P-DP 0.0000000 0.0106684 0.0106684 0.0000000 1,964.15 231.72 3.58 65.06 169.63 1,282.43 0 BOENING UNIT 6L P-DP 0.0000000 0.0106684 0.0106684 0.0000000 1,610.48 219.59 3.58 65.06 114.33 872.75 0 BOENING UNIT 6U P-DP 0.0000000 0.0106684 0.0106684 0.0000000 1,554.52 265.59 3.58 65.06 104.55 595.19 0 BONACCI 1 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 89.05 0.00 2.75 64.56 0.00 89.05 0 BONACCI 2 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 75.45 0.00 2.75 64.56 0.00 75.45 0 BOREAS 79 1H P-DP 0.0000000 0.0002688 0.0002688 0.0000000 916.96 390.30 2.38 64.55 241.94 608.97 0 BORUM E SMF JF 4H P-DP 0.0000000 0.0003647 0.0003647 0.0000000 11,631.21 0.00 3.33 64.56 0.00 8,681.67 0 BORUM E SMF JF 6H P-DP 0.0000000 0.0003647 0.0003647 0.0000000 13,187.75 0.00 3.33 64.56 0.00 9,103.58 0 BORUM W SMF JF 2H P-DP 0.0000000 0.0013045 0.0013045 0.0000000 11,101.16 0.00 3.33 64.56 0.00 7,889.61 0 BOX NAIL 2LM P-DP 0.0000000 0.0000713 0.0000713 0.0000000 986.22 448.17 3.11 65.50 245.25 347.96 0 BOX NAIL 3LL P-DP 0.0000000 0.0000709 0.0000709 0.0000000 1,022.54 335.38 3.11 65.50 233.13 366.69 0 BOX NAIL E 1LM P-DP 0.0000000 0.0000706 0.0000706 0.0000000 959.90 390.44 3.11 65.50 210.44 385.38 0 BRACERO 226-34 UNIT 1H P-DP 0.0000000 0.0011740 0.0011740 0.0000000 1,870.50 143.17 3.60 65.04 76.13 796.25 0 BRAMBLETT 34-216 1H P-DP 0.0000000 0.0014654 0.0014654 0.0000000 966.62 165.33 3.60 65.04 113.08 704.42 0 BRAUN B W1 2001MH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 762.05 745.29 3.43 66.60 362.00 309.10 0 BRAUN B W3 2001LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 803.94 746.88 3.43 66.60 323.37 312.27 0 BRAUN C W5 2108LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 907.57 611.44 3.43 66.60 243.76 266.55 0 BROOKE 184-185 UNIT 2H P-DP 0.0000000 0.0000650 0.0000650 0.0000000 8,356.82 673.31 3.60 65.04 315.80 3,447.66 0 BRUNSON 14 1 P-DP 0.0000000 0.0001586 0.0001586 0.0000000 1,646.14 0.36 3.40 65.18 0.36 1,386.31 0 BUCKEYE 55-1-28 UNIT 1H P-DP 0.0000000 0.0000895 0.0000895 0.0000000 3,522.52 728.98 3.40 65.18 378.03 2,012.53 0 BUELL 10-11-5 10H P-DP 0.0000000 0.0940794 0.0940794 0.0000000 16,920.84 15.90 3.19 58.51 15.90 11,190.28 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA BUELL 10-11-5 1H P-DP 0.0000000 0.0209883 0.0209883 0.0000000 6,038.03 47.75 3.19 58.51 46.52 4,514.43 0 BUELL 10-11-5 206H P-DP 0.0000000 0.0749937 0.0749937 0.0000000 16,807.96 42.16 3.19 58.51 41.82 11,233.03 0 BUELL 10-11-5 210H P-DP 0.0000000 0.0940794 0.0940794 0.0000000 16,221.62 12.40 3.19 58.51 12.40 10,938.62 0 BUELL 10-11-5 2H P-DP 0.0000000 0.0209883 0.0209883 0.0000000 6,011.60 39.15 3.19 58.51 37.51 4,642.98 0 BUELL 10-11-5 3H P-DP 0.0000000 0.0209883 0.0209883 0.0000000 6,160.69 43.49 3.19 58.51 42.43 4,775.18 0 BUELL 10-11-5 4H P-DP 0.0000000 0.0209883 0.0209883 0.0000000 7,368.21 52.82 3.19 58.51 46.04 5,673.91 0 BUELL 10-11-5 6H P-DP 0.0000000 0.0452066 0.0452066 0.0000000 15,525.10 22.17 3.19 58.51 22.17 10,288.61 0 BURKHOLDER A UNIT 1 P-DP 0.0000000 0.0001481 0.0001481 0.0000000 5,591.09 0.01 3.60 65.04 0.01 5,548.47 0 BUZZARD NORTH 6972 A 1H P-DP 0.0000000 0.0009749 0.0009749 0.0000000 3,598.02 1,075.15 2.38 64.55 805.09 2,427.90 0 BUZZARD NORTH 6972 B 2H P-DP 0.0000000 0.0009749 0.0009749 0.0000000 1,554.86 352.90 2.38 64.55 99.72 348.85 0 BUZZARD NORTH 6972 S 3H P-DP 0.0000000 0.0009749 0.0009749 0.0000000 1,567.41 345.44 2.38 64.55 59.93 224.34 0 Buzzard South 6972 A3H P-DP 0.0000000 0.0011548 0.0011548 0.0000000 2,698.11 508.79 2.38 64.55 116.53 407.92 0 BUZZARD SOUTH 6972 B 1H P-DP 0.0000000 0.0011548 0.0011548 0.0000000 2,274.03 854.38 2.38 64.55 537.27 1,604.45 0 BYRD 34-170 UNIT 3H P-DP 0.0000000 0.0002005 0.0002005 0.0000000 742.56 407.18 3.60 65.04 271.28 540.44 0 BYRD 34-170 UNIT 4H P-DP 0.0000000 0.0002005 0.0002005 0.0000000 538.63 184.18 3.60 65.04 173.06 359.15 0 CALIFORNIA CHROME UNIT 2H P-DP 0.0000000 0.0008218 0.0008218 0.0000000 7,426.37 678.96 3.60 65.04 368.57 4,054.39 0 CALIFORNIA CHROME UNIT 5003HR P-DP 0.0000000 0.0008218 0.0008218 0.0000000 6,430.09 654.90 3.60 65.04 351.16 3,911.72 0 CATES 24 1 P-DP 0.0000000 0.0043750 0.0043750 0.0000000 69.13 50.35 3.39 66.02 35.98 68.77 0 CENA WYN JF 2H P-DP 0.0000000 0.0653532 0.0653532 0.0000000 15,353.55 0.00 3.33 64.56 0.00 10,322.72 0 CENA WYN JF 4H P-DP 0.0000000 0.0653532 0.0653532 0.0000000 9,721.46 0.00 3.33 64.56 0.00 7,476.80 0 CHALUPA 34-153 UNIT 1H P-DP 0.0000000 0.0030208 0.0030208 0.0000000 1,703.57 743.44 3.60 65.04 413.17 807.67 0 CHALUPA 34-153 UNIT 2H P-DP 0.0000000 0.0030208 0.0030208 0.0000000 1,726.75 1,122.66 3.60 65.04 606.99 971.08 0 CHAPARRAL UNIT A1 15SH P-DP 0.0000000 0.0012015 0.0012015 0.0000000 874.21 570.62 3.39 66.02 211.30 170.08 0 CHAPARRAL UNIT A1 21H P-DP 0.0000000 0.0012015 0.0012015 0.0000000 884.40 643.43 3.39 66.02 168.13 129.74 0 CHAPARRAL UNIT A1 8AH P-DP 0.0000000 0.0012015 0.0012015 0.0000000 1,597.01 729.53 3.39 66.02 198.52 252.51 0 CHARLES ADAMCHICK 4 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 58.13 0.00 3.33 64.56 0.00 36.44 0 CHARLES ADAMCHICK 5 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 58.46 0.00 3.33 64.56 0.00 41.72 0 CHARLES ADAMCHICK 7 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 149.00 0.00 3.33 64.56 0.00 136.76 0 CHARLIE 210468 7A P-DP 0.0000000 0.0018185 0.0018185 0.0000000 15,579.88 0.00 2.82 64.56 0.00 7,822.54 0 CHARLIE 210468 8B P-DP 0.0000000 0.0018185 0.0018185 0.0000000 14,115.54 0.00 2.82 64.56 0.00 7,647.29 0 CHARLIE 210469 10B P-DP 0.0000000 0.0172842 0.0172842 0.0000000 18,658.89 0.00 2.82 64.56 0.00 9,609.77 0 CHARLIE 210469 9A P-DP 0.0000000 0.0172842 0.0172842 0.0000000 19,358.34 0.00 2.82 64.56 0.00 9,747.57 0 CHARLIE 210472 4A P-DP 0.0000000 0.0386492 0.0386492 0.0000000 8,783.66 0.00 2.82 64.56 0.00 7,718.74 0 CHARLIE 210472 5B P-DP 0.0000000 0.0386492 0.0386492 0.0000000 10,452.19 0.00 2.82 64.56 0.00 8,483.02 0 CHARLIE 210472 6C P-DP 0.0000000 0.0386492 0.0386492 0.0000000 9,493.30 0.00 2.82 64.56 0.00 8,080.94 0 CHILI PEPPER 34-137 UNIT 1H P-DP 0.0000000 0.0001953 0.0001953 0.0000000 1,671.11 762.91 3.60 65.04 370.23 708.09 0 CHINOOK 55-1-7 UNIT 1H P-DP 0.0000000 0.0001410 0.0001410 0.0000000 3,186.30 513.07 3.40 65.18 284.76 1,685.54 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA CHUMCHAL UNIT 1H P-DP 0.0000000 0.0101899 0.0101899 0.0000000 463.98 119.13 3.58 65.06 118.15 421.06 0 CHUMCHAL UNIT 2H P-DP 0.0000000 0.0101899 0.0101899 0.0000000 340.75 93.46 3.58 65.06 93.05 314.18 0 CHUMCHAL UNIT 3H P-DP 0.0000000 0.0101899 0.0101899 0.0000000 478.63 123.65 3.58 65.06 121.76 454.81 0 CHUMCHAL UNIT 4H P-DP 0.0000000 0.0101899 0.0101899 0.0000000 584.82 136.35 3.58 65.06 113.15 489.35 0 CHUMCHAL UNIT 6L P-DP 0.0000000 0.0101899 0.0101899 0.0000000 1,704.41 236.39 3.58 65.06 155.38 931.72 0 CHUMCHAL UNIT 7L P-DP 0.0000000 0.0101899 0.0101899 0.0000000 1,558.53 244.74 3.58 65.06 169.51 1,044.70 0 CHURRO 34-157/158 UNIT 1H P-DP 0.0000000 0.0001395 0.0001395 0.0000000 1,931.77 1,195.77 3.60 65.04 544.43 877.57 0 COLE 36-37 A UNIT A 2H P-DP 0.0000000 0.0001085 0.0001085 0.0000000 45.82 162.02 3.39 66.02 70.90 16.42 0 COLLE UNIT 1H P-DP 0.0000000 0.0199165 0.0199165 0.0000000 1,602.71 206.72 3.58 65.06 152.64 1,123.16 0 COLLINS WYN JF 2H P-DP 0.0000000 0.1005277 0.1005277 0.0000000 8,408.93 0.00 3.33 64.56 0.00 6,256.32 0 COLLINS WYN JF 4H P-DP 0.0000000 0.1005277 0.1005277 0.0000000 9,362.85 0.00 3.33 64.56 0.00 6,632.68 0 COLLINS WYN JF 6H P-DP 0.0000000 0.1005277 0.1005277 0.0000000 9,972.05 0.00 3.33 64.56 0.00 7,076.42 0 COLUMBINE 34-167 1H P-DP 0.0000000 0.0000337 0.0000337 0.0000000 298.80 191.19 3.60 65.04 145.78 240.53 0 COLUMBINE 34-167 2H P-DP 0.0000000 0.0000337 0.0000337 0.0000000 735.11 456.43 3.60 65.04 346.06 553.80 0 COLUMBINE 34-167 3H P-DP 0.0000000 0.0000337 0.0000337 0.0000000 373.45 61.06 3.60 65.04 52.74 314.87 0 COLUMBINE 34-167 4H P-DP 0.0000000 0.0000337 0.0000337 0.0000000 924.83 373.34 3.60 65.04 275.31 695.85 0 CONSTANTAN 34-174 (N) 1H P-DP 0.0000000 0.0000090 0.0000090 0.0000000 4,275.99 798.10 3.60 65.04 486.50 2,565.67 0 CORNELL 226-34 1H P-DP 0.0000000 0.0002385 0.0002385 0.0000000 3,384.66 317.30 3.60 65.04 165.68 1,872.24 0 CRAZY CAMEL 1 P-DP 0.0000000 0.0021149 0.0021149 0.0000000 44.93 29.29 3.60 65.04 13.38 19.97 0 CROSS CREEK A 5H-20 P-DP 0.0000000 0.1190618 0.1190618 0.0000000 9,030.19 0.00 3.33 64.56 0.00 6,625.15 0 CROSS V RANCH 34-170 UNIT 1H P-DP 0.0000000 0.0004007 0.0004007 0.0000000 1,525.33 695.90 3.60 65.04 303.84 616.05 0 CROWIE E RCH BL 3H P-DP 0.0000000 0.0016896 0.0016896 0.0000000 17,251.69 0.00 2.82 64.56 0.00 10,127.35 0 CROWIE RCH BL 1H P-DP 0.0000000 0.0016896 0.0016896 0.0000000 10,504.48 0.00 2.82 64.56 0.00 5,164.47 0 CV RA SU127;PACE ETAL 8-17 HC 001 P-DP 0.0000000 0.0009078 0.0009078 0.0000000 5,160.88 10.26 3.17 64.56 9.86 3,815.95 0 CV RA SU91;EDGAR S TALBERT 9 H 001 P-DP 0.0000000 0.0011082 0.0011082 0.0000000 2,979.51 8.87 3.17 64.56 8.87 2,215.26 0 CV RB SU58;SJ MONDELLO ETAL 18 001 P-DP 0.0000000 0.0156250 0.0156250 0.0000000 386.08 0.00 2.98 64.56 0.00 365.43 0 CV RB SUV;SHELBY INTERESTS 31 001 P-DP 0.0000000 0.0192857 0.0192857 0.0000000 518.44 1.24 3.17 64.56 1.24 474.83 0 CV RB SUW;LESHE 36 001 P-DP 0.0000000 0.0986163 0.0986163 0.0000000 1,234.92 0.27 3.17 64.56 0.27 1,048.64 0 CV RB SUW;NAC 36 001-ALT P-DP 0.0000000 0.0986163 0.0986163 0.0000000 628.63 0.26 3.17 64.56 0.26 541.40 0 DANIEL D & EDNA MILLER 1 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 92.08 0.00 2.75 64.56 0.00 92.08 0 DANIELLE 183 UNIT 1H P-DP 0.0000000 0.0001309 0.0001309 0.0000000 4,341.96 671.69 3.60 65.04 306.69 2,218.15 0 DANIELLE 183 UNIT 2H P-DP 0.0000000 0.0001309 0.0001309 0.0000000 5,311.98 683.27 3.60 65.04 323.10 2,581.34 0 DAVID L BONACCI 0031 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 40.42 0.00 2.75 64.56 0.00 40.42 0 DAVIS 1 P-DP 0.0000000 0.1158071 0.1158071 0.0000000 40.75 0.00 2.75 64.56 0.00 40.75 0 DAVIS 201-200-199 UNIT 1H P-DP 0.0000000 0.0002820 0.0002820 0.0000000 5,728.26 383.34 3.60 65.04 205.27 3,334.80 0 DEVILS CASTLE 1H P-DP 0.0000000 0.0000094 0.0000094 0.0000000 9,242.98 631.11 3.60 65.04 203.75 2,685.40 0 DICKSON CRC JF 1H P-DP 0.0000000 0.1203236 0.1203236 0.0000000 14,367.88 0.00 3.33 64.56 0.00 10,451.46 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA DICKSON CRC JF 3H P-DP 0.0000000 0.1203236 0.1203236 0.0000000 13,258.06 0.00 3.33 64.56 0.00 9,404.44 0 DILLES BOTTOM 210744 3B P-DP 0.0000000 0.0000137 0.0000137 0.0000000 14,160.90 0.00 2.82 64.56 0.00 11,226.63 0 DONALDSON 4-54 1H P-DP 0.0000000 0.0031797 0.0031797 0.0000000 3,808.29 89.55 2.38 64.55 72.87 2,460.87 0 DONALDSON 4-54 U 34H P-DP 0.0000000 0.0002250 0.0002250 0.0000000 3,806.82 160.93 2.38 64.55 83.91 1,664.03 0 DOYEN NE WEL JF 3H P-DP 0.0000000 0.0093247 0.0093247 0.0000000 17,858.96 0.00 3.33 64.56 0.00 4,088.55 0 DOYEN NW WEL JF 1H P-DP 0.0000000 0.0002367 0.0002367 0.0000000 15,616.91 0.00 3.33 64.56 0.00 4,218.81 0 DRAINAGE 34-136 1H P-DP 0.0000000 0.0003759 0.0003759 0.0000000 440.66 280.37 3.60 65.04 162.19 323.48 0 DRAINAGE 34-136 2H P-DP 0.0000000 0.0003759 0.0003759 0.0000000 575.87 257.98 3.60 65.04 193.32 401.59 0 DRAINAGE 34-136 3H P-DP 0.0000000 0.0003759 0.0003759 0.0000000 510.56 515.43 3.60 65.04 458.04 473.86 0 DRAINAGE 34-136 4H P-DP 0.0000000 0.0003759 0.0003759 0.0000000 597.33 554.81 3.60 65.04 427.09 562.63 0 EILAND 1806A-33 1H P-DP 0.0000000 0.0003115 0.0003115 0.0000000 1,182.21 453.57 3.60 65.04 318.67 633.16 0 EILAND 1806B-33 1H P-DP 0.0000000 0.0002850 0.0002850 0.0000000 869.24 781.51 3.60 65.04 414.86 525.87 0 EILAND 1806B-33 62H P-DP 0.0000000 0.0002850 0.0002850 0.0000000 694.11 549.97 3.60 65.04 303.87 402.70 0 EILAND 1806C-33 1H P-DP 0.0000000 0.0002850 0.0002850 0.0000000 724.03 425.60 3.60 65.04 345.86 547.09 0 EILAND 1806C-33 83H P-DP 0.0000000 0.0002850 0.0002850 0.0000000 881.33 533.95 3.60 65.04 252.81 339.46 0 EILAND 6047A-34 41H P-DP 0.0000000 0.0021636 0.0021636 0.0000000 956.26 560.51 3.60 65.04 356.61 574.16 0 EL KABONG UNIT 48-17-8 301H P-DP 0.0000000 0.0002629 0.0002629 0.0000000 435.06 460.27 3.97 59.61 234.38 200.35 0 EL KABONG UNIT 48-17-8 302H P-DP 0.0000000 0.0002629 0.0002629 0.0000000 483.85 472.94 3.97 59.61 203.91 230.32 0 EL KABONG UNIT 48-17-8 701H P-DP 0.0000000 0.0002629 0.0002629 0.0000000 308.27 402.38 3.97 59.61 180.01 142.05 0 EL KABONG UNIT 48-17-8 702H P-DP 0.0000000 0.0002629 0.0002629 0.0000000 762.97 930.22 3.97 59.61 469.02 328.59 0 EL KABONG UNIT 48-17-8 703H P-DP 0.0000000 0.0002629 0.0002629 0.0000000 565.88 585.74 3.97 59.61 262.97 172.96 0 EL KABONG UNIT 48-17-8 704H P-DP 0.0000000 0.0002629 0.0002629 0.0000000 434.47 433.55 3.97 59.61 237.68 216.18 0 EL KABONG UNIT 48-17-8 801H P-DP 0.0000000 0.0002629 0.0002629 0.0000000 376.66 167.77 3.97 59.61 131.87 302.58 0 ELKHEAD 4144 A 2H P-DP 0.0000000 0.0004602 0.0004602 0.0000000 6,183.28 957.37 2.38 64.55 588.97 3,586.76 0 ELKHEAD 4144 A 5H P-DP 0.0000000 0.0004602 0.0004602 0.0000000 5,397.68 622.54 2.38 64.55 264.06 1,785.21 0 ELKHEAD 4144 A 7H P-DP 0.0000000 0.0004602 0.0004602 0.0000000 4,835.11 623.47 2.38 64.55 308.63 2,120.57 0 ELKHEAD 4144 B 1H P-DP 0.0000000 0.0004602 0.0004602 0.0000000 5,690.05 1,419.30 2.38 64.55 1,168.67 4,312.78 0 ELKHEAD 4144 B 6H P-DP 0.0000000 0.0004602 0.0004602 0.0000000 2,434.56 309.92 2.38 64.55 167.13 1,142.53 0 ELKHEAD 4144 B 8H P-DP 0.0000000 0.0004602 0.0004602 0.0000000 4,027.34 525.67 2.38 64.55 229.52 1,613.58 0 ELKHEAD 4144 C 4H P-DP 0.0000000 0.0004602 0.0004602 0.0000000 3,114.98 387.87 2.38 64.55 196.61 1,256.29 0 ELKHEAD 4144 S 3H P-DP 0.0000000 0.0004602 0.0004602 0.0000000 3,647.81 601.45 2.38 64.55 245.63 1,432.24 0 ELUSIVE JAZZ 167-168 2HA P-DP 0.0000000 0.0000168 0.0000168 0.0000000 1,299.96 613.66 3.60 65.04 349.99 663.32 0 ELY GAS UNIT NO. 2 1 P-DP 0.0000000 0.0079574 0.0079574 0.0000000 1,512.51 0.00 3.72 64.56 0.00 1,224.88 0 EMMA 218-219 UNIT 1H P-DP 0.0000000 0.0001208 0.0001208 0.0000000 7,300.73 511.32 3.60 65.04 214.63 3,743.03 0 EUGENE L CONDOR NT243 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 254.99 0.00 2.75 64.56 0.00 254.99 0 FAIREY UNIT 1H P-DP 0.0000000 0.0187018 0.0187018 0.0000000 559.15 141.12 3.39 66.02 111.96 374.48 0 FIELDS UNIT 1H P-DP 0.0000000 0.0217246 0.0217246 0.0000000 944.24 128.60 3.58 65.06 101.82 717.27 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA FIELDS UNIT 2H P-DP 0.0000000 0.0217246 0.0217246 0.0000000 735.57 85.33 3.58 65.06 70.55 593.72 0 FIELDS UNIT 3H P-DP 0.0000000 0.0217246 0.0217246 0.0000000 605.82 98.11 3.58 65.06 81.35 482.31 0 FIELDS UNIT 4H P-DP 0.0000000 0.0217246 0.0217246 0.0000000 649.89 80.34 3.58 65.06 72.82 435.96 0 FINLEY 1-11 WRD 1H P-DP 0.0000000 0.0002124 0.0002124 0.0000000 1,100.39 345.79 3.60 65.04 245.69 746.38 0 FINLEY 1-11 WRD 2H P-DP 0.0000000 0.0002124 0.0002124 0.0000000 119.54 429.86 3.60 65.04 305.64 86.01 0 Fire Frog 1 ** P-DP 0.0000000 0.0006432 0.0006432 0.0000000 1,826.09 586.57 3.60 65.04 130.79 391.09 0 Fire Frog 2 ** P-DP 0.0000000 0.0006432 0.0006432 0.0000000 4,316.76 594.44 3.60 65.04 79.04 454.27 0 Fire Frog 3 ** P-DP 0.0000000 0.0006432 0.0006432 0.0000000 3,405.13 915.04 3.60 65.04 226.88 667.57 0 Fire Frog 4 ** P-DP 0.0000000 0.0006432 0.0006432 0.0000000 3,640.27 905.84 3.60 65.04 233.16 689.15 0 FIREBIRD 52 1 P-DP 0.0000000 0.0001179 0.0001179 0.0000000 281.19 22.36 3.60 65.04 18.22 232.82 0 FISHERMAN -A- 1 P-DP 0.0000000 0.0052083 0.0052083 0.0000000 147.28 74.43 3.11 65.50 58.18 145.56 0 FISHERMAN -A- 2 P-DP 0.0000000 0.0052083 0.0052083 0.0000000 105.56 34.50 3.11 65.50 20.01 88.55 0 FISHERMAN-BRISTOW 23A 1H P-DP 0.0000000 0.0037045 0.0037045 0.0000000 264.32 339.98 3.11 65.50 156.24 120.34 0 FISHERMAN-BRISTOW 23B 2H P-DP 0.0000000 0.0037783 0.0037783 0.0000000 612.82 593.93 3.11 65.50 186.28 169.37 0 FISHERMAN-BRISTOW 23C 3H P-DP 0.0000000 0.0037009 0.0037009 0.0000000 606.45 529.61 3.11 65.50 217.03 181.00 0 FISHERMAN-BRISTOW 23D 4H P-DP 0.0000000 0.0037701 0.0037701 0.0000000 665.60 717.19 3.11 65.50 244.57 194.37 0 FLEMING 13 10H P-DP 0.0000000 0.0040391 0.0040391 0.0000000 4,545.44 112.68 2.38 64.55 63.50 2,017.42 0 FUNKY BOSS B 8251H P-DP 0.0000000 0.0000010 0.0000010 0.0000000 5,702.84 1,347.45 3.60 65.04 739.10 3,089.86 0 FUNKY BOSS C 8270H P-DP 0.0000000 0.0000010 0.0000010 0.0000000 4,654.74 595.88 3.60 65.04 327.49 1,957.89 0 GADDIE 1-31 UNIT 1H P-DP 0.0000000 0.0000335 0.0000335 0.0000000 1,492.46 631.57 3.60 65.04 422.81 911.96 0 GADDIE 1-31 UNIT 2H P-DP 0.0000000 0.0000335 0.0000335 0.0000000 677.26 326.30 3.60 65.04 209.75 468.31 0 GADDIE 1-31 UNIT 3H P-DP 0.0000000 0.0000335 0.0000335 0.0000000 141.55 267.68 3.60 65.04 207.43 52.03 0 GENFIVE ENERGY LLC UNIT P-DP 0.0000000 0.1250000 0.1250000 0.0000000 13,341.73 0.17 2.75 64.56 0.17 12,841.27 0 GEORGE T STAGG 5-2 UNIT 1H P-DP 0.0000000 0.0034293 0.0034293 0.0000000 2,569.80 96.66 2.38 64.55 62.13 1,636.09 0 GERDES UNIT 1H P-DP 0.0000000 0.0176399 0.0176399 0.0000000 832.85 181.88 3.58 65.06 168.52 741.93 0 GERDES UNIT 2H P-DP 0.0000000 0.0176399 0.0176399 0.0000000 878.00 153.54 3.58 65.06 127.54 462.05 0 GERDES UNIT 3H P-DP 0.0000000 0.0176399 0.0176399 0.0000000 634.18 164.31 3.58 65.06 142.61 496.03 0 GERDES UNIT 4H P-DP 0.0000000 0.0176399 0.0176399 0.0000000 1,015.00 191.38 3.58 65.06 154.45 777.58 0 GERDES UNIT 5H P-DP 0.0000000 0.0176399 0.0176399 0.0000000 1,154.32 192.42 3.58 65.06 133.12 827.64 0 GERDES UNIT 6H P-DP 0.0000000 0.0176399 0.0176399 0.0000000 1,233.02 202.75 3.58 65.06 134.96 839.18 0 GERDES-LANGHOFF 1L P-DP 0.0000000 0.0140696 0.0140696 0.0000000 2,002.16 350.45 3.58 65.06 212.35 1,166.44 0 GERDES-RATHKAMP 1L P-DP 0.0000000 0.0124874 0.0124874 0.0000000 2,032.35 364.23 3.58 65.06 206.45 1,139.81 0 GILLESPIE UNIT 1H P-DP 0.0000000 0.0262016 0.0262016 0.0000000 296.29 164.15 3.39 66.02 136.49 284.94 0 GLASS RANCH 19 2HA P-DP 0.0000000 0.0002266 0.0002266 0.0000000 334.37 66.77 3.11 65.50 63.50 238.54 0 GORDON SE CRC JF 4H P-DP 0.0000000 0.0752589 0.0752589 0.0000000 10,651.39 0.00 3.33 64.56 0.00 8,356.05 0 GORDON SE CRC JF 6H P-DP 0.0000000 0.0752589 0.0752589 0.0000000 11,653.20 0.00 3.33 64.56 0.00 7,865.51 0 GORDON SW CRC JF 2H P-DP 0.0000000 0.0871079 0.0871079 0.0000000 8,989.06 0.00 3.33 64.56 0.00 7,221.10 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA GRANT 18A 4HK P-DP 0.0000000 0.0009554 0.0009554 0.0000000 1,232.64 442.46 3.39 66.02 191.44 357.88 0 GRANT 18B 5HJ P-DP 0.0000000 0.0006149 0.0006149 0.0000000 992.36 555.31 3.39 66.02 288.86 342.11 0 GRANT 18B 6HK P-DP 0.0000000 0.0006149 0.0006149 0.0000000 1,121.91 366.86 3.39 66.02 239.22 452.29 0 GRISWOLD S WYN JF 4H P-DP 0.0000000 0.0357289 0.0357289 0.0000000 12,630.17 0.00 3.33 64.56 0.00 9,697.59 0 GRISWOLD SW WYN JF 2H P-DP 0.0000000 0.0092237 0.0092237 0.0000000 13,250.49 0.00 3.33 64.56 0.00 10,223.56 0 GRISWOLD WYN JF 6H P-DP 0.0000000 0.0740675 0.0740675 0.0000000 8,467.52 0.00 3.33 64.56 0.00 6,772.53 0 GRISWOLD WYN JF 8H P-DP 0.0000000 0.0740675 0.0740675 0.0000000 10,274.26 0.00 3.33 64.56 0.00 7,188.08 0 GRIZZLY BEAR 7780 2U A 2H P-DP 0.0000000 0.0006487 0.0006487 0.0000000 1,971.09 504.55 2.38 64.55 276.04 851.56 0 GRIZZLY BEAR 7780 3U A 3H P-DP 0.0000000 0.0006490 0.0006490 0.0000000 2,228.55 275.14 2.38 64.55 178.35 916.00 0 GRIZZLY BEAR 7780 4U A 4H P-DP 0.0000000 0.0006540 0.0006540 0.0000000 2,567.31 505.21 2.38 64.55 255.08 978.07 0 GRIZZLY BEAR 7780 5U A 5H P-DP 0.0000000 0.0006460 0.0006460 0.0000000 1,070.95 184.34 2.38 64.55 161.36 737.43 0 GRIZZLY BEAR 7780 6U A 6H P-DP 0.0000000 0.0006488 0.0006488 0.0000000 3,238.14 582.05 2.38 64.55 334.82 1,141.37 0 GRIZZLY SOUTH 7673 A 1H P-DP 0.0000000 0.0019953 0.0019953 0.0000000 1,816.67 862.04 2.38 64.55 726.97 1,438.40 0 GRIZZLY SOUTH 7673 A 3H P-DP 0.0000000 0.0019953 0.0019953 0.0000000 793.25 232.72 2.38 64.55 97.87 289.51 0 GRIZZLY SOUTH 7673 A 5H P-DP 0.0000000 0.0019953 0.0019953 0.0000000 1,716.14 584.21 2.38 64.55 175.27 431.97 0 GRIZZLY SOUTH 7673 A 8H P-DP 0.0000000 0.0019953 0.0019953 0.0000000 1,175.21 425.29 2.38 64.55 147.62 303.28 0 GRIZZLY SOUTH 7673 B 2H P-DP 0.0000000 0.0019953 0.0019953 0.0000000 2,493.48 647.09 2.38 64.55 540.93 1,794.88 0 GRIZZLY SOUTH 7673 B 4H P-DP 0.0000000 0.0019953 0.0019953 0.0000000 662.00 169.09 2.38 64.55 38.52 150.27 0 GRIZZLY SOUTH 7673 B 6H P-DP 0.0000000 0.0019953 0.0019953 0.0000000 2,366.95 584.54 2.38 64.55 143.55 435.18 0 GRIZZLY WEST 77 1H P-DP 0.0000000 0.0010076 0.0010076 0.0000000 2,016.30 487.92 2.38 64.55 272.00 811.46 0 GRIZZLY WEST 77 A 3H P-DP 0.0000000 0.0010076 0.0010076 0.0000000 1,128.23 258.83 2.38 64.55 144.94 665.85 0 GRIZZLY WEST 77 C 2H P-DP 0.0000000 0.0010076 0.0010076 0.0000000 895.66 183.75 2.38 64.55 102.57 598.15 0 GUITAR 11 1 P-DP 0.0000000 0.0041667 0.0041667 0.0000000 96.75 46.79 3.39 66.02 43.05 79.11 0 GUITAR 13 1 P-DP 0.0000000 0.0041111 0.0041111 0.0000000 176.62 71.73 3.39 66.02 60.83 147.36 0 GUNSLINGER UNIT L 4H P-DP 0.0000000 0.0002894 0.0002894 0.0000000 337.48 485.10 3.39 66.02 295.50 209.49 0 GUNSMOKE 1-40 (ALLOC 1-NH) 4LB ** P-DP 0.0000000 0.0018411 0.0018411 0.0000000 689.20 424.67 3.11 65.50 118.03 135.13 0 GUNSMOKE 1-40 (ALLOC-2NH) 3LA ** P-DP 0.0000000 0.0018411 0.0018411 0.0000000 1,199.36 875.83 3.11 65.50 175.09 188.86 0 GUY COWDEN UNIT 2 2505BH P-DP 0.0000000 0.0005088 0.0005088 0.0000000 927.32 233.93 3.43 66.60 149.60 856.65 0 GUY COWDEN UNIT 2 2506BH P-DP 0.0000000 0.0005088 0.0005088 0.0000000 3,704.26 318.27 3.43 66.60 206.37 1,617.45 0 GUY COWDEN UNIT 2 2507BH P-DP 0.0000000 0.0005088 0.0005088 0.0000000 723.88 137.00 3.43 66.60 123.35 618.30 0 GUY COWDEN UNIT 2 2508BH P-DP 0.0000000 0.0005088 0.0005088 0.0000000 4,210.42 550.56 3.43 66.60 353.26 2,259.71 0 GUY COWDEN UNIT 2 2515AH P-DP 0.0000000 0.0005088 0.0005088 0.0000000 2,430.07 202.66 3.43 66.60 181.64 1,062.79 0 GUY COWDEN UNIT 2 2516AH P-DP 0.0000000 0.0005088 0.0005088 0.0000000 1,859.89 640.21 3.43 66.60 417.77 1,009.10 0 GUY COWDEN UNIT 2 2517AH P-DP 0.0000000 0.0005088 0.0005088 0.0000000 3,290.52 327.11 3.43 66.60 229.93 1,995.98 0 GUY COWDEN UNIT 2 2518AH P-DP 0.0000000 0.0005088 0.0005088 0.0000000 1,709.16 625.44 3.43 66.60 378.51 1,081.34 0 HA RA SU77;LEE 25-36 HC 001-ALT P-DP 0.0000000 0.0092009 0.0092009 0.0000000 7,158.23 0.00 3.17 64.56 0.00 2,528.24 0 HA RA SU98;PACE 8-14-16 H 001 P-DP 0.0000000 0.0010694 0.0010694 0.0000000 4,132.09 0.00 3.17 64.56 0.00 3,413.35 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA HA RA SUA;GOLSON 36-25 HC 001-ALT P-DP 0.0000000 0.0986163 0.0986163 0.0000000 4,215.43 0.00 3.10 64.56 0.00 1,034.38 0 HA RA SUA;GOLSON 36-25 HC 002-ALT P-DP 0.0000000 0.0986163 0.0986163 0.0000000 4,267.07 0.00 3.10 64.56 0.00 1,068.86 0 HA RA SUA;NAC 36 H 001-ALT (3 Wells) P-DP 0.0000000 0.0986163 0.0986163 0.0000000 20,981.99 0.00 3.17 66.56 0.00 13,496.13 0 HA RA SUA;WIGGINS 36-25 HC 001 P-DP 0.0000000 0.0493230 0.0493230 0.0000000 14,537.47 0.00 2.98 64.56 0.00 9,306.83 0 HA RA SUA;WIGGINS 36-25 HC 002-ALT P-DP 0.0000000 0.0503545 0.0503545 0.0000000 15,284.81 0.00 2.98 64.56 0.00 10,732.16 0 HA RA SUB;SHELBY INTERESTS 31H 001 P-DP 0.0000000 0.0192857 0.0192857 0.0000000 5,973.78 0.00 3.17 64.56 0.00 5,973.78 0 HA RA SUCC;BAKER 7-11-14 H 001 P-DP 0.0000000 0.0034880 0.0034880 0.0000000 2,381.87 0.00 3.10 64.56 0.00 2,262.69 0 HA RA SUL;L & L INV 18-19 HC 001-ALT P-DP 0.0000000 0.0012590 0.0012590 0.0000000 12,377.25 0.00 2.98 64.56 0.00 8,702.34 0 HA RA SUL;L & L INV 18-19 HC 002-ALT P-DP 0.0000000 0.0013872 0.0013872 0.0000000 11,517.58 0.00 2.98 64.56 0.00 9,127.71 0 HA RA SUL;MADDEN 18 H 001 P-DP 0.0000000 0.0156397 0.0156397 0.0000000 2,486.32 0.00 2.98 64.56 0.00 2,412.80 0 HA RA SUL;MADDEN 18 H 002-ALT P-DP 0.0000000 0.0156397 0.0156397 0.0000000 7,545.65 0.00 2.98 64.56 0.00 5,819.44 0 HA RA SUL;MADDEN 18-19 HC 001-ALT P-DP 0.0000000 0.0019049 0.0019049 0.0000000 9,130.58 0.00 2.98 64.56 0.00 7,378.05 0 HA RA SUL;TALBERT 9-14-16 H 001 P-DP 0.0000000 0.0011292 0.0011292 0.0000000 6,054.79 0.00 3.17 64.56 0.00 5,047.57 0 HA RA SUS;POOLE-DRAKE 21 H 001 P-DP 0.0000000 0.1176788 0.1176788 0.0000000 9,427.39 0.00 2.98 64.56 0.00 7,995.58 0 HA RA SUSS;JORDAN 16-21 HC 001-ALT P-DP 0.0000000 0.0004531 0.0004531 0.0000000 9,557.57 0.00 3.10 64.56 0.00 9,378.28 0 HA RA SUTT;BSMC LA 21 HZ 001 P-DP 0.0000000 0.0006879 0.0006879 0.0000000 4,033.67 0.00 3.10 64.56 0.00 3,858.86 0 HA RA SUZ;GLOVER 20 001 P-DP 0.0000000 0.0078075 0.0078075 0.0000000 10,114.37 0.00 2.98 64.56 0.00 9,168.59 0 HA RA SUZ;GLOVER 20 002-ALT P-DP 0.0000000 0.0078075 0.0078075 0.0000000 10,928.38 0.00 2.98 64.56 0.00 9,079.26 0 HA RA SUZ;GLOVER 20 003-ALT P-DP 0.0000000 0.0078075 0.0078075 0.0000000 10,897.81 0.00 2.98 64.56 0.00 9,455.21 0 HA RA SUZ;JUNCACEAE 20 001-ALT P-DP 0.0000000 0.0078075 0.0078075 0.0000000 8,239.10 0.00 2.98 64.56 0.00 7,761.36 0 HA RA SUZ;JUNCACEAE 20 002-ALT P-DP 0.0000000 0.0078075 0.0078075 0.0000000 9,227.05 0.00 2.98 64.56 0.00 8,466.02 0 HA RA SUZ;JUNCACEAE 20 003-ALT P-DP 0.0000000 0.0078075 0.0078075 0.0000000 11,280.79 0.00 2.98 64.56 0.00 9,427.14 0 HA RB SU69;NAC ROYALTY 33 H 001 P-DP 0.0000000 0.0782261 0.0782261 0.0000000 5,999.70 0.00 2.98 64.56 0.00 5,345.99 0 HA RB SU74;NAC ROYALTY 28 H 001 P-DP 0.0000000 0.1311698 0.1311698 0.0000000 4,776.34 0.00 2.98 64.56 0.00 4,776.34 0 HA RB SU77;WAHL 27 H 001 P-DP 0.0000000 0.0437142 0.0437142 0.0000000 4,740.54 0.00 2.98 64.56 0.00 4,675.20 0 HA RB SU90;NRG 29-12-10 H 001 P-DP 0.0000000 0.0375773 0.0375773 0.0000000 5,913.20 0.00 2.98 64.56 0.00 4,533.76 0 HA RB SU90;NRG 29-12-10 H 002-ALT P-DP 0.0000000 0.0375773 0.0375773 0.0000000 21,298.05 0.00 3.10 64.56 0.00 13,959.71 0 HA RB SU92;NAC ROYALTY 34 H 001 P-DP 0.0000000 0.1572809 0.1572809 0.0000000 1,276.89 0.00 2.98 64.56 0.00 1,222.77 0 HALL TRUST 38 1 P-DP 0.0000000 0.0039063 0.0039063 0.0000000 379.75 214.78 3.11 65.50 136.98 327.90 0 HALL TRUST 38 2 P-DP 0.0000000 0.0039063 0.0039063 0.0000000 236.16 174.44 3.11 65.50 88.69 196.22 0 HALL-PORTER 621-596 A 112 P-DP 0.0000000 0.0014830 0.0014830 0.0000000 1,049.69 450.52 3.43 66.60 197.29 309.14 0 HALL-PORTER 621-596 A 211 P-DP 0.0000000 0.0014830 0.0014830 0.0000000 1,751.34 574.54 3.43 66.60 307.76 546.19 0 HALL-PORTER 621-596 B 122 P-DP 0.0000000 0.0014830 0.0014830 0.0000000 1,228.93 343.69 3.43 66.60 213.79 438.85 0 HALL-PORTER 621-596 B 221 P-DP 0.0000000 0.0014830 0.0014830 0.0000000 1,456.35 266.87 3.43 66.60 144.73 552.65 0 HALL-PORTER 621-596 B 224 P-DP 0.0000000 0.0014830 0.0014830 0.0000000 1,508.00 242.17 3.43 66.60 153.42 477.64 0 HALL-PORTER 621-596 C 132 P-DP 0.0000000 0.0014830 0.0014830 0.0000000 1,272.70 332.05 3.43 66.60 186.74 501.16 0 HALL-PORTER 621-596 C 231R P-DP 0.0000000 0.0007406 0.0007406 0.0000000 1,564.29 401.59 3.43 66.60 211.27 625.80 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA HALL-PORTER 621-596 C 233 P-DP 0.0000000 0.0014830 0.0014830 0.0000000 1,417.29 339.51 3.43 66.60 186.54 542.95 0 HALL-PORTER 621-596 D 142 P-DP 0.0000000 0.0008464 0.0008464 0.0000000 842.81 448.84 3.43 66.60 219.46 385.59 0 HALL-PORTER 621-596 D 241 P-DP 0.0000000 0.0008464 0.0008464 0.0000000 1,037.92 529.01 3.43 66.60 362.81 600.96 0 HARGROVE, BETTY 1 P-DP 0.0000000 0.0159713 0.0159713 0.0000000 227.32 0.00 2.38 64.55 0.00 181.46 0 HAWKS 55-1-28 UNIT 1H P-DP 0.0000000 0.0000624 0.0000624 0.0000000 3,842.54 712.31 3.40 65.18 430.96 1,957.74 0 HENDERSHOT 210471 1A P-DP 0.0000000 0.0003040 0.0003040 0.0000000 12,754.31 0.00 2.82 64.56 0.00 5,040.18 0 HENDERSHOT 210471 2B P-DP 0.0000000 0.0003040 0.0003040 0.0000000 13,836.07 0.00 2.82 64.56 0.00 5,502.60 0 HOERMANN UNIT 1H P-DP 0.0000000 0.0100962 0.0100962 0.0000000 506.80 160.92 3.58 65.06 148.28 488.23 0 HOERMANN UNIT 2H P-DP 0.0000000 0.0100962 0.0100962 0.0000000 906.97 209.04 3.58 65.06 167.11 720.30 0 HOERMANN UNIT 3H P-DP 0.0000000 0.0100962 0.0100962 0.0000000 2,167.66 364.10 3.58 65.06 240.63 1,437.95 0 HOERMANN UNIT 4H P-DP 0.0000000 0.0100962 0.0100962 0.0000000 1,642.75 344.16 3.58 65.06 211.73 1,051.18 0 HORNSILVER 1H P-DP 0.0000000 0.0001203 0.0001203 0.0000000 6,089.80 487.17 3.60 65.04 232.71 2,949.21 0 HULING 'A' 18-7 ESL (ALLOC) 1HA P-DP 0.0000000 0.0004419 0.0004419 0.0000000 1,009.44 207.05 3.25 65.49 134.42 564.00 0 HULING 'D' 18-7 ESL (ALLOC) 4HS P-DP 0.0000000 0.0004425 0.0004425 0.0000000 298.20 117.10 3.25 65.49 97.07 212.99 0 HYDRA 45-4 UNIT 1 112 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 787.57 503.55 3.11 65.50 112.06 132.04 0 HYDRA 45-4 UNIT 1 122 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 727.51 418.64 3.11 65.50 94.36 113.52 0 HYDRA 45-4 UNIT 1 124 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 1,076.09 687.78 3.11 65.50 145.22 171.56 0 HYDRA 45-4 UNIT 1 132 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 1,241.34 753.77 3.11 65.50 166.48 208.66 0 HYDRA 45-4 UNIT 1 142 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 843.99 441.69 3.11 65.50 93.89 129.21 0 HYDRA 45-4 UNIT 1 211 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 558.01 566.60 3.11 65.50 126.26 139.34 0 HYDRA 45-4 UNIT 1 221 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 709.83 822.12 3.11 65.50 219.73 70.69 0 HYDRA 45-4 UNIT 1 223 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 1,045.79 563.62 3.11 65.50 142.07 171.60 0 HYDRA 45-4 UNIT 1 231 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 622.92 460.31 3.11 65.50 99.29 102.29 0 HYDRA 45-4 UNIT 1 241 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 1,114.36 696.37 3.11 65.50 180.87 210.72 0 JACKSON A 34-166-175 5201H P-DP 0.0000000 0.0000000 0.0000000 0.0000000 1,066.72 526.64 3.60 65.04 279.37 606.46 0 JANAK UNIT 3H P-DP 0.0000000 0.0251620 0.0251620 0.0000000 759.76 108.66 3.58 65.06 86.75 627.87 0 JANAK UNIT 4H P-DP 0.0000000 0.0251620 0.0251620 0.0000000 803.74 128.23 3.58 65.06 104.35 662.88 0 JANAK UNIT 5H P-DP 0.0000000 0.0251620 0.0251620 0.0000000 1,152.50 147.95 3.58 65.06 120.19 886.38 0 JANAK UNIT 7L P-DP 0.0000000 0.0251620 0.0251620 0.0000000 502.75 61.58 3.58 65.06 44.57 384.92 0 JANAK-LOOS 6L P-DP 0.0000000 0.0128380 0.0128380 0.0000000 1,000.87 125.55 3.58 65.06 76.73 669.59 0 JMW NAIL 10 1 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 182.15 69.63 3.11 65.50 64.02 122.94 0 JMW NAIL 10 2 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 187.67 30.04 3.11 65.50 26.17 92.24 0 JMW NAIL 10 3 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 159.79 29.07 3.11 65.50 25.16 82.27 0 JMW NAIL 10 4 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 155.32 40.10 3.11 65.50 33.79 86.10 0 JMW NAIL 10A 3 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 119.75 14.15 3.11 65.50 5.78 22.63 0 JMW NAIL 10A 4 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 107.49 18.85 3.11 65.50 5.88 21.70 0 JUR RA SUG;OLYMPIA MIN 30 H 001 P-DP 0.0000000 0.0026730 0.0026730 0.0000000 7,287.18 0.00 3.17 64.56 0.00 7,106.80 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA KAISER UNIT 1H P-DP 0.0000000 0.0189370 0.0189370 0.0000000 816.34 96.09 3.58 65.06 87.49 689.78 0 KAISER UNIT 4H P-DP 0.0000000 0.0189370 0.0189370 0.0000000 987.23 110.90 3.58 65.06 95.81 839.47 0 KAISER UNIT 5H P-DP 0.0000000 0.0189370 0.0189370 0.0000000 1,352.38 126.65 3.58 65.06 102.66 1,113.21 0 KENOSHA 4441 1H P-DP 0.0000000 0.0004248 0.0004248 0.0000000 7,989.84 819.22 2.38 64.55 571.66 4,803.86 0 KENOSHA 4441 B 2H P-DP 0.0000000 0.0004248 0.0004248 0.0000000 4,551.15 757.84 2.38 64.55 377.25 2,351.48 0 KENTEX-HARRISON 35A 1H P-DP 0.0000000 0.0034390 0.0034390 0.0000000 647.66 636.93 3.11 65.50 252.92 211.75 0 KENTEX-HARRISON 35B 2H P-DP 0.0000000 0.0042984 0.0042984 0.0000000 768.76 470.54 3.11 65.50 142.69 187.55 0 KENTEX-HARRISON 35C 3H P-DP 0.0000000 0.0034390 0.0034390 0.0000000 641.82 645.52 3.11 65.50 222.37 188.04 0 KENTEX-HARRISON 35D 4H P-DP 0.0000000 0.0042984 0.0042984 0.0000000 719.84 392.02 3.11 65.50 115.19 166.49 0 KEYHOLE 43 1H P-DP 0.0000000 0.0004034 0.0004034 0.0000000 2,220.07 648.76 2.38 64.55 425.89 1,387.03 0 KINGSLEY 10HK P-DP 0.0000000 0.0010712 0.0010712 0.0000000 723.02 519.56 3.39 66.02 147.83 158.65 0 KINGSLEY 3HK P-DP 0.0000000 0.0014262 0.0014262 0.0000000 761.88 527.03 3.39 66.02 142.38 160.64 0 KINGSLEY 4HJ P-DP 0.0000000 0.0038606 0.0038606 0.0000000 669.96 565.81 3.39 66.02 164.90 173.89 0 KINGSLEY 5HK P-DP 0.0000000 0.0038423 0.0038423 0.0000000 833.99 499.38 3.39 66.02 160.06 182.36 0 KINGSLEY 6HF P-DP 0.0000000 0.0038583 0.0038583 0.0000000 1,145.63 433.39 3.39 66.02 102.62 241.48 0 KINGSLEY 7HJ P-DP 0.0000000 0.0010875 0.0010875 0.0000000 712.06 518.22 3.39 66.02 145.13 154.76 0 KINGSLEY 8HK P-DP 0.0000000 0.0010708 0.0010708 0.0000000 798.79 523.72 3.39 66.02 151.44 192.25 0 KINGSLEY 9HJ P-DP 0.0000000 0.0010795 0.0010795 0.0000000 575.76 494.86 3.39 66.02 122.77 128.88 0 KRAKEN 10-3 E1 251 P-DP 0.0000000 0.0005532 0.0005532 0.0000000 838.44 601.82 3.39 66.02 276.74 292.98 0 KRAKEN 10-3 UNIT 2 153 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 625.43 501.15 3.39 66.02 138.22 142.40 0 KRAKEN 10-3 UNIT 2 162 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 711.47 595.75 3.39 66.02 162.99 166.44 0 KRAKEN 10-3 UNIT 2 171 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 917.75 807.80 3.39 66.02 154.20 162.47 0 KRAKEN 10-3 UNIT 2 181 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 1,076.00 661.28 3.11 65.50 150.97 165.33 0 KRAKEN 10-3 UNIT 2 183 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 753.81 431.06 3.11 65.50 99.78 116.22 0 KRAKEN 10-3 UNIT 2 252 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 484.81 462.82 3.39 66.02 194.11 161.42 0 KRAKEN 10-3 UNIT 2 261 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 694.09 631.10 3.39 66.02 121.34 125.01 0 KRAKEN 10-3 UNIT 2 272 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 781.64 634.77 3.39 66.02 144.94 155.87 0 KRAKEN 10-3 UNIT 2 273 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 369.28 344.95 3.11 65.50 66.19 57.89 0 KRAKEN 10-3 UNIT 2 282 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 1,077.25 601.17 3.11 65.50 177.49 193.46 0 KRUPA 210483 3A P-DP 0.0000000 0.0425468 0.0425468 0.0000000 13,061.57 0.00 2.82 64.56 0.00 10,083.59 0 KRUPA 211259 2A P-DP 0.0000000 0.0130602 0.0130602 0.0000000 16,605.22 0.00 2.82 64.56 0.00 11,557.44 0 KUBENKA UNIT 1H P-DP 0.0000000 0.0279630 0.0279630 0.0000000 258.70 116.38 3.39 66.02 90.59 202.45 0 L E STARTZELL 2 P-DP 0.0000000 0.0301781 0.0301781 0.0000000 106.21 0.00 2.75 64.56 0.00 106.21 0 L E STARTZELL UNIT BR 19 4 P-DP 0.0000000 0.0301780 0.0301780 0.0000000 117.43 0.00 2.75 64.56 0.00 117.43 0 L E STARTZELL UNIT BR 19 5 P-DP 0.0000000 0.0301780 0.0301780 0.0000000 73.89 0.00 2.75 64.56 0.00 73.89 0 LANE, ROWENA 11D P-DP 0.0000000 0.0014351 0.0000000 0.0000000 0.00 47.40 3.39 66.02 47.40 0.00 0 LANGHOFF UNIT A 1H P-DP 0.0000000 0.0103536 0.0103536 0.0000000 1,641.45 215.44 3.58 65.06 213.49 1,425.17 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA LANGHOFF UNIT A 2H P-DP 0.0000000 0.0103536 0.0103536 0.0000000 667.33 132.59 3.58 65.06 128.09 638.16 0 LANGHOFF UNIT A 3H P-DP 0.0000000 0.0103536 0.0103536 0.0000000 486.54 65.16 3.58 65.06 61.90 388.29 0 LANGHOFF UNIT A 4H P-DP 0.0000000 0.0103536 0.0103536 0.0000000 818.55 125.43 3.58 65.06 118.87 779.03 0 LANGHOFF UNIT A 8L P-DP 0.0000000 0.0103536 0.0103536 0.0000000 1,769.38 147.01 3.58 65.06 76.05 826.64 0 LANGHOFF UNIT A 9L P-DP 0.0000000 0.0103536 0.0103536 0.0000000 1,206.94 94.96 3.58 65.06 48.21 568.38 0 LANGHOFF UNIT B 701 P-DP 0.0000000 0.0021378 0.0021378 0.0000000 1,803.32 184.01 3.58 65.06 131.34 1,054.16 0 LAURA WILDER 72-69 UNIT A 3H P-DP 0.0000000 0.0002037 0.0002037 0.0000000 4,029.41 1,037.25 2.38 64.55 668.08 2,427.11 0 LAURA WILDER 72-69 UNIT B 4HL P-DP 0.0000000 0.0001452 0.0001452 0.0000000 1,700.59 527.79 2.38 64.55 353.16 1,045.18 0 LAWSON 31-30 HC 001 P-DP 0.0000000 0.0073240 0.0073240 0.0000000 8,629.71 0.00 2.98 64.56 0.00 7,424.62 0 LAWSON 31-30-19 HC 002 P-DP 0.0000000 0.0073300 0.0073300 0.0000000 9,025.27 0.00 2.98 64.56 0.00 7,806.61 0 LAWSON 31-30-19 HC 003 P-DP 0.0000000 0.0099298 0.0099298 0.0000000 9,044.64 0.00 2.98 64.56 0.00 7,825.98 0 LEE 34-154 1H P-DP 0.0000000 0.0045313 0.0045313 0.0000000 257.40 151.93 3.60 65.04 119.14 181.89 0 LEEDE UNIT 7 1H P-DP 0.0000000 0.0005495 0.0005495 0.0000000 655.98 463.57 3.60 65.04 348.56 515.75 0 LEEDE UNIT 7 2H P-DP 0.0000000 0.0005495 0.0005495 0.0000000 453.82 283.02 3.60 65.04 202.56 345.47 0 LONG 18 1 P-DP 0.0000000 0.0032222 0.0032222 0.0000000 45.31 29.44 3.39 66.02 23.36 35.92 0 LOOS UNIT 10H P-DP 0.0000000 0.0124811 0.0124811 0.0000000 447.61 90.58 3.58 65.06 84.30 414.44 0 LOOS UNIT 11L P-DP 0.0000000 0.0124811 0.0124811 0.0000000 2,173.48 265.53 3.58 65.06 156.34 1,062.58 0 LOOS UNIT 12L P-DP 0.0000000 0.0124811 0.0124811 0.0000000 1,981.28 188.95 3.58 65.06 110.17 974.03 0 LOOS UNIT 1H P-DP 0.0000000 0.0124811 0.0124811 0.0000000 565.61 155.20 3.58 65.06 152.38 553.50 0 LOOS UNIT 2H P-DP 0.0000000 0.0124811 0.0000000 0.0000000 427.17 96.81 3.58 65.06 96.81 427.17 0 LOOS UNIT 3H P-DP 0.0000000 0.0124811 0.0124811 0.0000000 354.04 77.65 3.58 65.06 70.97 295.67 0 LOOS UNIT 8H P-DP 0.0000000 0.0124811 0.0124811 0.0000000 319.89 75.81 3.58 65.06 69.51 277.14 0 LOOS UNIT 9H P-DP 0.0000000 0.0124811 0.0124811 0.0000000 1,087.22 214.45 3.58 65.06 147.33 768.35 0 LOST SADDLE 45 1H P-DP 0.0000000 0.0001628 0.0001628 0.0000000 2,002.76 237.68 2.38 64.55 162.83 1,548.21 0 LRT UNIT 2 ALLOCATION 2318AH P-DP 0.0000000 0.0002397 0.0002397 0.0000000 2,258.81 669.97 3.43 66.60 349.32 818.65 0 MABEE 22A 1H P-DP 0.0000000 0.0000159 0.0000159 0.0000000 688.07 303.24 3.43 66.60 145.93 253.86 0 MABEE DDA J8 3HK P-DP 0.0000000 0.0000068 0.0000068 0.0000000 313.77 316.59 3.39 66.02 82.63 79.73 0 MABEE-ELKIN W16B 2H P-DP 0.0000000 0.0000068 0.0000068 0.0000000 991.98 380.01 3.43 66.60 155.10 292.17 0 MABEE-STIMSON 22B 2H P-DP 0.0000000 0.0000537 0.0000537 0.0000000 1,073.28 340.19 3.43 66.60 172.59 360.54 0 MABEE-TREDAWAY W16A 1H P-DP 0.0000000 0.0000067 0.0000067 0.0000000 1,056.67 336.56 3.43 66.60 180.51 388.67 0 MACHICEK UNIT 1H P-DP 0.0000000 0.0035717 0.0035717 0.0000000 1,959.42 203.08 3.39 66.02 195.13 1,866.09 0 MARY GRACE 201-202 UNIT 1H P-DP 0.0000000 0.0001950 0.0001950 0.0000000 5,305.00 549.30 3.60 65.04 239.05 2,179.50 0 MARY GRACE 201-202 UNIT 3H P-DP 0.0000000 0.0001950 0.0001950 0.0000000 4,205.90 477.23 3.60 65.04 229.30 2,248.21 0 MARYRUTH-ANDERSON 47C 103H P-DP 0.0000000 0.0002698 0.0002698 0.0000000 692.47 703.41 3.11 65.50 455.50 398.20 0 MARYRUTH-ANDERSON 47D 104H P-DP 0.0000000 0.0002697 0.0002697 0.0000000 619.38 541.83 3.11 65.50 375.18 340.24 0 MARYRUTH-ANDERSON 47E 105H P-DP 0.0000000 0.0002696 0.0002696 0.0000000 687.65 539.96 3.11 65.50 334.40 353.92 0 MARYRUTH-ANDERSON 47F 106H P-DP 0.0000000 0.0002695 0.0002695 0.0000000 579.37 667.98 3.11 65.50 433.82 320.97 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA MATTIE 18-11-5 6H P-DP 0.0000000 0.0413913 0.0413913 0.0000000 6,956.61 32.24 3.19 58.51 32.24 4,608.05 0 MATTIE 18-11-5 7H P-DP 0.0000000 0.0413913 0.0413913 0.0000000 5,628.29 34.26 3.19 58.51 34.26 4,130.60 0 MATTIE 18-11-5 8H P-DP 0.0000000 0.0413913 0.0413913 0.0000000 7,398.23 38.27 3.19 58.51 35.05 4,975.24 0 MCCONNELL 4 P-DP 0.0000000 0.1100000 0.1100000 0.0000000 118.69 0.00 2.75 64.56 0.00 118.69 0 MEADOR, J. J. 3 P-DP 0.0000000 0.0003120 0.0003120 0.0000000 255.36 93.52 3.39 66.02 83.33 174.89 0 MEHAFFEY - BURNEM 1 P-DP 0.0000000 0.0625000 0.0625000 0.0000000 192.87 0.96 3.67 64.56 0.96 187.38 0 MELISSA A 1 P-DP 0.0000000 0.0003638 0.0003638 0.0000000 365.61 30.27 3.60 65.04 23.47 361.60 0 MERIDITH 183 UNIT 1H P-DP 0.0000000 0.0000983 0.0000983 0.0000000 2,528.69 327.94 3.60 65.04 154.75 1,333.02 0 MIDDLETON 21 1 P-DP 0.0000000 0.0041667 0.0041667 0.0000000 203.08 25.96 3.39 66.02 17.57 144.71 0 MIMS 32H 3306BH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 982.70 264.24 3.11 65.50 227.78 705.70 0 MIMS 32H 3307BH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 998.79 240.93 3.11 65.50 199.47 717.57 0 MIMS 32H 3315AH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 860.80 350.23 3.11 65.50 296.75 690.65 0 MIMS 32H 3317AH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 953.02 181.01 3.11 65.50 156.15 665.39 0 MIMS 32H 3318AH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 517.91 265.67 3.11 65.50 228.34 401.66 0 MIMS 32H 3326SH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 771.17 218.32 3.11 65.50 181.11 552.56 0 MIMS 32H 3327SH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 428.47 223.52 3.11 65.50 185.50 310.83 0 MIMS 32H 3345SH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 546.30 492.15 3.11 65.50 426.64 382.50 0 MIMS 32H 3347SH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 441.30 264.46 3.11 65.50 233.20 396.47 0 MIMS 32H 3348SH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 729.68 418.59 3.11 65.50 320.08 510.67 0 MINGO S CRC JF 4H P-DP 0.0000000 0.0209787 0.0209787 0.0000000 12,601.96 0.00 3.33 64.56 0.00 10,513.89 0 MINGO SE CRC JF 6H P-DP 0.0000000 0.0409383 0.0409383 0.0000000 14,285.48 0.00 3.33 64.56 0.00 10,983.42 0 MINGO SW CRC JF 2H P-DP 0.0000000 0.0095069 0.0095069 0.0000000 12,052.86 0.00 3.33 64.56 0.00 9,806.82 0 MINGO W CRC JF 8H P-DP 0.0000000 0.0412216 0.0412216 0.0000000 8,471.80 0.00 3.33 64.56 0.00 7,030.41 0 MOLNOSKEY UNIT 1H P-DP 0.0000000 0.0230365 0.0230365 0.0000000 364.10 161.58 3.39 66.02 145.61 323.80 0 MOLNOSKEY UNIT 2H P-DP 0.0000000 0.0230365 0.0230365 0.0000000 438.99 176.27 3.39 66.02 123.48 267.11 0 MONROE 34-158 UNIT 1H P-DP 0.0000000 0.0002791 0.0002791 0.0000000 505.75 334.94 3.60 65.04 320.61 476.29 0 MONROE 34-158 UNIT 2H P-DP 0.0000000 0.0002791 0.0002791 0.0000000 618.68 454.41 3.60 65.04 448.47 614.80 0 MONROE 34-158 UNIT 3H P-DP 0.0000000 0.0002791 0.0002791 0.0000000 532.57 342.27 3.60 65.04 317.11 500.89 0 MONROE 34-158 UNIT 4H P-DP 0.0000000 0.0002791 0.0002791 0.0000000 170.50 167.25 3.60 65.04 166.32 170.22 0 Mud Hen 1 ** P-DP 0.0000000 0.0005049 0.0005049 0.0000000 2,120.83 500.19 3.60 65.04 132.76 307.42 0 Mud Hen 2 ** P-DP 0.0000000 0.0005049 0.0005049 0.0000000 2,324.95 832.78 3.60 65.04 206.49 588.64 0 Mud Hen 3 ** P-DP 0.0000000 0.0005049 0.0005049 0.0000000 2,753.44 671.35 3.60 65.04 125.39 312.87 0 Mud Hen 4 ** P-DP 0.0000000 0.0005049 0.0005049 0.0000000 2,985.62 789.99 3.60 65.04 191.84 585.14 0 N A C R C 1 - 15 ACRES 1 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 31.56 0.00 2.75 64.56 0.00 31.56 0 N A C R C 5-132 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 69.03 0.00 2.75 64.56 0.00 69.03 0 NAC 3H-20 P-DP 0.0000000 0.1190618 0.1190618 0.0000000 6,920.67 0.00 3.33 64.56 0.00 5,095.46 0 NAC 3P-20 P-DP 0.0000000 0.1190618 0.1190618 0.0000000 1,352.51 0.00 3.33 64.56 0.00 507.43 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA NAC 4H-20 P-DP 0.0000000 0.1190618 0.1190618 0.0000000 6,461.82 0.00 3.33 64.56 0.00 4,800.45 0 NAC B WYN JF 1H P-DP 0.0000000 0.1157926 0.1157926 0.0000000 6,472.13 0.00 3.33 64.56 0.00 5,238.75 0 NAC B WYN JF 3H P-DP 0.0000000 0.1157926 0.1157926 0.0000000 4,482.39 0.00 3.33 64.56 0.00 3,613.97 0 NAC B WYN JF 5H P-DP 0.0000000 0.1157926 0.1157926 0.0000000 7,045.07 0.00 3.33 64.56 0.00 5,865.68 0 NAC GAS UNIT B 3H-3 P-DP 0.0000000 0.1157926 0.1157926 0.0000000 6,719.22 0.07 3.33 64.56 0.07 5,200.51 0 NAIL RANCH 10 1 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 188.19 64.83 3.11 65.50 42.80 106.51 0 NAIL RANCH 10 2 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 137.33 74.85 3.11 65.50 51.56 86.88 0 NAIL RANCH 10 3 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 112.50 80.98 3.11 65.50 54.39 67.39 0 NAIL RANCH 10 4 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 268.97 98.92 3.11 65.50 64.97 164.34 0 NANCY 1H P-DP 0.0000000 0.0044356 0.0044356 0.0000000 988.24 150.62 3.39 66.02 107.74 728.27 0 NE NAIL 10 1 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 144.27 68.57 3.11 65.50 48.87 75.47 0 NE NAIL 10 2 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 403.90 91.12 3.11 65.50 54.38 208.79 0 NE NAIL 10 3 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 233.46 105.64 3.11 65.50 88.98 148.83 0 NE NAIL 10 4 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 105.18 14.85 3.11 65.50 9.13 54.64 0 NE NAIL 10 5 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 108.10 18.90 3.11 65.50 12.16 56.82 0 NEWTON 43A 1HE P-DP 0.0000000 0.0011938 0.0011938 0.0000000 1,039.34 296.70 3.39 66.02 164.44 424.49 0 NEWTON 43A 2HK P-DP 0.0000000 0.0011912 0.0011912 0.0000000 578.73 343.50 3.39 66.02 206.19 343.55 0 NEWTON 43B 3HJ P-DP 0.0000000 0.0004990 0.0004990 0.0000000 632.84 284.10 3.39 66.02 255.04 437.45 0 NEWTON 43B 4HE P-DP 0.0000000 0.0010780 0.0010780 0.0000000 562.59 47.64 3.39 66.02 26.34 353.41 0 NEWTON 43B 5HK P-DP 0.0000000 0.0010780 0.0010780 0.0000000 390.96 259.25 3.39 66.02 223.06 148.18 0 NEWTON 43BK 4HE P-DP 0.0000000 0.0010780 0.0010780 0.0000000 502.30 135.97 3.39 66.02 36.72 106.46 0 NEWTON 43BK 5HK P-DP 0.0000000 0.0010802 0.0010802 0.0000000 876.86 274.53 3.39 66.02 74.62 186.96 0 NEWTON 43C 6HJ P-DP 0.0000000 0.0000000 0.0000000 0.0000000 696.02 449.75 3.39 66.02 296.61 333.68 0 NM HARRISON 16-11-5 10H P-DP 0.0000000 0.0154884 0.0154884 0.0000000 5,546.13 19.18 3.19 58.51 18.63 4,222.96 0 NM HARRISON 16-11-5 6H P-DP 0.0000000 0.0155018 0.0155018 0.0000000 7,246.03 63.68 3.19 58.51 55.70 5,318.08 0 NM HARRISON 16-11-5 8H P-DP 0.0000000 0.0154886 0.0154886 0.0000000 7,427.74 44.94 3.19 58.51 44.86 5,901.26 0 NOLAN NE CRC JF 3H P-DP 0.0000000 0.0915912 0.0915912 0.0000000 8,833.17 0.00 3.33 64.56 0.00 7,562.54 0 NOLAN NW CRC JF 1H P-DP 0.0000000 0.0972461 0.0972461 0.0000000 22,937.09 0.00 3.33 64.56 0.00 16,239.62 0 NOLAN S CRC JF 2H P-DP 0.0000000 0.0982250 0.0982250 0.0000000 11,161.69 0.00 3.33 64.56 0.00 8,631.94 0 NOLAN S CRC JF 4H P-DP 0.0000000 0.0982250 0.0982250 0.0000000 9,319.18 0.00 3.33 64.56 0.00 7,113.47 0 NOLAN S CRC JF 6H P-DP 0.0000000 0.0972461 0.0972461 0.0000000 10,085.91 0.00 3.33 64.56 0.00 7,813.19 0 NORRIS UNIT 32-H 3301BH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 430.64 257.85 3.11 65.50 28.36 41.77 0 NORRIS UNIT 32-H 3303BH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 705.43 330.66 3.11 65.50 41.48 52.31 0 NORRIS UNIT 32-H 3304BH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 205.63 256.22 3.11 65.50 40.99 18.02 0 NORRIS UNIT 32-H 3312AH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 440.87 209.54 3.11 65.50 23.89 43.66 0 NORRIS UNIT 32-H 3313AH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 781.99 274.77 3.11 65.50 39.05 81.03 0 NORRIS UNIT 32-H 3322SH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 535.99 348.51 3.11 65.50 65.23 75.90 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA NORRIS UNIT 32-H 3323SH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 1,195.72 663.53 3.11 65.50 148.67 227.15 0 NORRIS UNIT 32-H 3361DH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 847.89 452.79 3.11 65.50 76.22 106.76 0 NORRIS UNIT 32-H 3363DH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 823.53 351.98 3.11 65.50 50.11 86.97 0 NORRIS UNIT 32-H 3364DH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 929.76 365.17 3.11 65.50 69.48 122.19 0 NORRIS UNIT 32-H 3371JH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 384.21 313.32 3.11 65.50 50.75 53.04 0 NORRIS UNIT 32-H 3373JH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 471.12 304.34 3.11 65.50 46.43 53.26 0 NORRIS UNIT 32-H 3374JH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 469.27 345.04 3.11 65.50 54.00 56.36 0 NORRIS-MIMS ALLOCATION 3315AH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 541.12 349.17 3.11 65.50 61.65 81.90 0 NORRIS-MIMS ALLOCATION 3325SH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 957.90 374.14 3.11 65.50 76.99 178.05 0 NORTH AMERICAN COAL 1S P-DP 0.0000000 0.1250000 0.1250000 0.0000000 35.31 0.00 2.75 64.56 0.00 35.31 0 NORTH AMERICAN COAL 2S P-DP 0.0000000 0.1250000 0.1250000 0.0000000 18.29 0.00 2.75 64.56 0.00 18.29 0 NORTH AMERICAN COAL 3A P-DP 0.0000000 0.1250000 0.1250000 0.0000000 94.87 0.00 2.75 64.56 0.00 94.87 0 NORTH AMERICAN COAL CO 4 P-DP 0.0000000 0.0919390 0.0919390 0.0000000 74.18 2.66 3.67 64.56 2.66 74.18 0 NORTH AMERICAN COAL CORP 1 P-DP 0.0000000 0.0560430 0.0560430 0.0000000 107.22 0.00 2.75 64.56 0.00 107.22 0 NORTH AMERICAN COAL CORP 1 P-DP 0.0000000 0.0560430 0.0560430 0.0000000 59.32 1.71 3.67 64.56 1.71 59.32 0 NORTH AMERICAN COAL CORP 2 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 88.16 0.00 2.75 64.56 0.00 88.16 0 NORTH AMERICAN COAL CORP 3 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 88.20 0.00 2.75 64.56 0.00 88.20 0 NORTH AMERICAN COAL CORP BR 19 UNIT 2 P-DP 0.0000000 0.0301780 0.0301780 0.0000000 126.31 0.00 2.75 64.56 0.00 126.31 0 NORTH AMERICAN COAL GAS UNIT 1 P-DP 0.0000000 0.0544738 0.0544738 0.0000000 1,280.20 0.05 3.72 64.56 0.05 971.45 0 NORTH AMERICAN COAL ROYALTY CO BUELL 1 P-DP 0.0000000 0.0788856 0.0788856 0.0000000 456.13 0.26 3.19 58.51 0.16 258.43 0 NORTH AMERICAN COAL ROYALTY CO BUELL 8H P-DP 0.0000000 0.0788856 0.0788856 0.0000000 9,856.87 32.83 3.19 58.51 32.59 8,556.47 0 NORTH AMERICAN COAL ROYALTY CO. 1 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 116.34 0.00 2.75 64.56 0.00 116.34 0 NORTH AMERICAN COAL ROYALTY CO. 2 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 66.09 0.00 2.75 64.56 0.00 66.09 0 OLDHAM-GRAHAM 35A 1H P-DP 0.0000000 0.0015563 0.0015563 0.0000000 328.74 236.07 3.43 66.60 53.61 47.35 0 OLDHAM-GRAHAM 35B 2H P-DP 0.0000000 0.0015563 0.0015563 0.0000000 734.00 371.72 3.43 66.60 73.72 105.71 0 OLDHAM-GRAHAM 35C 3H P-DP 0.0000000 0.0015563 0.0015563 0.0000000 385.69 292.90 3.43 66.60 79.11 80.65 0 OLDHAM-GRAHAM 35D 4H P-DP 0.0000000 0.0015563 0.0015563 0.0000000 1,166.39 370.01 3.43 66.60 75.14 104.98 0 OLDHAM-GRAHAM 35E 5H P-DP 0.0000000 0.0015563 0.0015563 0.0000000 324.68 213.54 3.43 66.60 56.76 62.32 0 OLDHAM-GRAHAM 35F #6H ** P-DP 0.0000000 0.0015563 0.0015563 0.0000000 542.87 336.61 3.43 66.60 84.43 93.26 0 PALOS 01-12-241 P-DP 0.0000000 0.1591250 0.1591250 0.0000000 193.57 0.00 3.33 64.56 0.00 193.57 0 PALOS 02-10-239 P-DP 0.0000000 0.0800417 0.0800417 0.0000000 251.89 0.00 3.33 64.56 0.00 251.89 0 PALOS 02-16-240 P-DP 0.0000000 0.1587292 0.1587292 0.0000000 298.90 0.00 3.33 64.56 0.00 271.70 0 PALOS 03-06-245 P-DP 0.0000000 0.1666667 0.1666667 0.0000000 228.04 0.00 3.33 64.56 0.00 228.04 0 PALOS 03-10-232 P-DP 0.0000000 0.1666667 0.1666667 0.0000000 309.94 0.00 3.33 64.56 0.00 309.94 0 PALOS 03-14-233 P-DP 0.0000000 0.1666667 0.1666667 0.0000000 314.26 0.00 3.33 64.56 0.00 314.26 0 PALOS 03-16-231 P-DP 0.0000000 0.1666667 0.1666667 0.0000000 469.66 0.00 3.17 64.56 0.00 469.66 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA PARKS FIELD UNIT #2 2401 P-DP 0.0000000 0.0008036 0.0008036 0.0000000 2,589.70 49.91 3.43 66.60 49.91 2,472.60 0 PARKS FIELD UNIT 2 1450BH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 2,633.49 536.43 3.43 66.60 340.81 1,060.89 0 PARKS FIELD UNIT 2 1450LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 2,053.05 1,186.01 3.43 66.60 712.44 953.17 0 PARKS FIELD UNIT 2 1451LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,652.68 1,029.32 3.43 66.60 655.45 819.87 0 PARKS FIELD UNIT 2 1454H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 761.55 381.49 3.43 66.60 317.97 496.76 0 PARKS FIELD UNIT 2 1454LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,309.74 919.27 3.43 66.60 640.29 713.57 0 PARKS FIELD UNIT 2 1455LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,326.33 732.90 3.43 66.60 468.60 569.01 0 PARKS FIELD UNIT 2 1458CH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 2,685.33 562.23 3.43 66.60 345.20 1,287.40 0 PARKS FIELD UNIT 2 1458LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,724.26 545.35 3.43 66.60 372.67 794.08 0 PARKS FIELD UNIT 2 1863BH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,408.73 418.37 3.43 66.60 324.38 768.93 0 PARKS FIELD UNIT 2 1863LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 977.17 639.54 3.43 66.60 525.84 642.01 0 PARKS FIELD UNIT 2 1904BH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,324.33 378.26 3.43 66.60 295.31 1,146.63 0 PARKS FIELD UNIT 2 1921H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 439.43 249.21 3.43 66.60 209.46 358.33 0 PARKS FIELD UNIT 2 2001BH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,698.23 348.11 3.43 66.60 150.46 461.83 0 PARKS FIELD UNIT 2 2308BH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,315.93 432.84 3.43 66.60 255.46 593.66 0 PARKS FIELD UNIT 2 2308LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,609.23 735.43 3.43 66.60 440.33 701.80 0 PARKS FIELD UNIT 2 2308MH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,555.80 822.44 3.43 66.60 505.64 718.89 0 PARKS FIELD UNIT 2 2329LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 938.47 501.00 3.43 66.60 417.55 533.70 0 PARKS FIELD UNIT 2 2336BH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 698.88 186.74 3.43 66.60 179.57 602.27 0 PARKS FIELD UNIT 2 2346CH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 85.51 33.49 3.43 66.60 33.49 85.51 0 PARKS FIELD UNIT 2 2348H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,059.21 375.76 3.43 66.60 264.86 767.77 0 PARKS FIELD UNIT 2 2401 P-DP 0.0000000 0.0008036 0.0008036 0.0000000 222.00 75.99 3.43 66.60 75.99 222.00 0 PARKS FIELD UNIT 2 2630H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,237.83 299.49 3.43 66.60 251.63 945.98 0 PARKS FIELD UNIT 2 2709H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,836.88 557.98 3.43 66.60 433.76 1,213.68 0 PARKS FIELD UNIT 2401W P-DP 0.0000000 0.0008036 0.0008036 0.0000000 80.71 0.13 3.43 66.60 0.07 13.85 0 PARKS FIELD UNIT NO 2 1320H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,841.38 37.55 3.43 66.60 26.55 1,319.96 0 PARKS FIELD UNIT NO. 2 1421H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 9,528.66 191.18 3.43 66.60 174.59 8,103.17 0 PARKS FIELD UNIT NO. 2 1422H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 8,424.54 156.64 3.43 66.60 138.94 7,112.89 0 PARKS FIELD UNIT NO. 2 1423H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,571.39 45.82 3.43 66.60 43.32 1,522.66 0 PARKS FIELD UNIT NO. 2 1829H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 3,544.85 52.07 3.43 66.60 52.07 3,180.71 0 PARKS FIELD UNIT NO. 2 1831H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 10,157.40 221.11 3.43 66.60 221.11 9,844.72 0 PARKS FIELD UNIT NO. 2 2324H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 4,152.42 112.21 3.43 66.60 103.09 3,404.13 0 PARKS FIELD UNIT NO. 2 2417H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 2,434.06 54.14 3.43 66.60 53.10 2,358.25 0 PARKS, CHARLOTTE 14 1 P-DP 0.0000000 0.0008036 0.0008036 0.0000000 14.46 55.23 3.43 66.60 52.51 13.86 0 PARKS, CHARLOTTE 7 1 P-DP 0.0000000 0.0008036 0.0008036 0.0000000 95.44 77.52 3.43 66.60 76.18 95.22 0 PARKS, ROY 306BH P-DP 0.0000000 0.0002678 0.0002678 0.0000000 645.74 319.82 3.43 66.60 264.93 408.81 0 PARKS, ROY 306LH P-DP 0.0000000 0.0002678 0.0002678 0.0000000 398.51 596.87 3.43 66.60 349.84 190.52 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA PARKS, ROY 307BH P-DP 0.0000000 0.0002678 0.0002678 0.0000000 733.47 284.80 3.43 66.60 225.19 336.23 0 PARKS, ROY 307LH P-DP 0.0000000 0.0002678 0.0002678 0.0000000 486.50 200.46 3.43 66.60 129.64 356.53 0 PARKS, ROY 308BH P-DP 0.0000000 0.0002678 0.0002678 0.0000000 553.25 307.97 3.43 66.60 191.72 199.64 0 PARKS, ROY 308LH P-DP 0.0000000 0.0002678 0.0002678 0.0000000 722.38 211.95 3.43 66.60 120.06 295.45 0 PARKS, ROY 308MH P-DP 0.0000000 0.0002678 0.0002678 0.0000000 516.16 681.60 3.43 66.60 372.91 230.31 0 PARKS, ROY 316CH P-DP 0.0000000 0.0002678 0.0002678 0.0000000 424.70 235.46 3.43 66.60 137.27 208.40 0 PARKS, ROY 316LH P-DP 0.0000000 0.0002678 0.0002678 0.0000000 387.35 325.31 3.43 66.60 251.11 166.47 0 PARKS, ROY 99H P-DP 0.0000000 0.0002678 0.0002678 0.0000000 530.62 313.34 3.43 66.60 221.63 481.35 0 PARKS-COYOTE 1506 A 1HM P-DP 0.0000000 0.0020089 0.0020089 0.0000000 942.90 366.32 3.43 66.60 216.34 447.19 0 PARKS-COYOTE 1506 B 2HM P-DP 0.0000000 0.0020089 0.0020089 0.0000000 1,653.68 339.01 3.43 66.60 177.63 520.87 0 PARKS-COYOTE 1506 C 3HM P-DP 0.0000000 0.0020089 0.0020089 0.0000000 1,632.57 389.18 3.43 66.60 205.76 580.56 0 PARKS-COYOTE 1506 D 4HM P-DP 0.0000000 0.0020089 0.0020089 0.0000000 1,729.09 443.06 3.43 66.60 226.70 554.06 0 PARKS-COYOTE 1506 E 5HM P-DP 0.0000000 0.0020089 0.0020089 0.0000000 1,011.26 439.42 3.43 66.60 238.44 426.44 0 PARKS-COYOTE 1506 F 6HM P-DP 0.0000000 0.0020089 0.0020089 0.0000000 1,056.34 450.75 3.43 66.60 233.67 414.80 0 PARKS-COYOTE 1506 G 7HM P-DP 0.0000000 0.0020089 0.0020089 0.0000000 946.77 587.31 3.43 66.60 279.75 364.69 0 PHILLIPS 7 1 P-DP 0.0000000 0.0031014 0.0031014 0.0000000 65.30 51.01 3.39 66.02 37.33 65.30 0 POTH UNIT 1H P-DP 0.0000000 0.0073981 0.0073981 0.0000000 1,782.22 176.79 3.58 65.06 132.31 1,277.11 0 PRIMA 1H P-DP 0.0000000 0.0003637 0.0003637 0.0000000 5,490.63 393.53 3.60 65.04 167.21 2,215.18 0 PRONTO 1H P-DP 0.0000000 0.0003630 0.0003630 0.0000000 2,726.84 258.80 3.60 65.04 110.29 1,224.63 0 PRUETT 20 2H P-DP 0.0000000 0.0000412 0.0000412 0.0000000 397.44 209.16 3.60 65.04 169.08 298.01 0 PRUETT 20 4H P-DP 0.0000000 0.0000412 0.0000412 0.0000000 185.62 206.14 3.60 65.04 160.71 126.34 0 PRUETT 20 5H P-DP 0.0000000 0.0000412 0.0000412 0.0000000 246.71 94.77 3.60 65.04 52.30 130.28 0 PRUETT 20 6H P-DP 0.0000000 0.0000412 0.0000412 0.0000000 726.66 378.28 3.60 65.04 243.71 439.58 0 PRUETT 23 2 P-DP 0.0000000 0.0000687 0.0000687 0.0000000 239.82 167.19 3.60 65.04 140.02 203.30 0 PRUETT 23 2H P-DP 0.0000000 0.0000687 0.0000687 0.0000000 128.74 133.91 3.60 65.04 106.17 106.39 0 PRUETT 23A 1H P-DP 0.0000000 0.0000687 0.0000687 0.0000000 352.22 211.26 3.60 65.04 128.00 206.62 0 PRUETT 23A 2H P-DP 0.0000000 0.0000687 0.0000687 0.0000000 313.78 204.57 3.60 65.04 116.69 170.49 0 PUGGLE E WYN JF 4H P-DP 0.0000000 0.1107177 0.1107177 0.0000000 10,994.47 0.00 3.33 64.56 0.00 7,726.67 0 PUGGLE E WYN JF 6H P-DP 0.0000000 0.1107177 0.1107177 0.0000000 11,045.89 0.00 3.33 64.56 0.00 7,476.39 0 PUGGLE W WYN JF 2H P-DP 0.0000000 0.1033932 0.1033932 0.0000000 12,482.15 0.00 3.33 64.56 0.00 8,345.86 0 QUESO 34-153 UNIT 1H P-DP 0.0000000 0.0030208 0.0030208 0.0000000 2,403.65 676.74 3.60 65.04 437.67 1,534.02 0 QUESO 34-153 UNIT 2H P-DP 0.0000000 0.0030208 0.0030208 0.0000000 2,929.20 728.98 3.60 65.04 489.95 1,430.18 0 QUICK SILVER 55-1-7 UNIT 1H P-DP 0.0000000 0.0001410 0.0001410 0.0000000 4,092.84 794.69 3.40 65.18 346.72 1,960.64 0 QUITO, S. W. (DELAWARE) UNIT 201 P-DP 0.0000000 0.0002557 0.0002557 0.0000000 43.52 32.12 3.60 65.04 27.75 37.65 0 QUITO, S. W. (DELAWARE) UNIT 801 P-DP 0.0000000 0.0002557 0.0002557 0.0000000 22.16 0.40 3.60 65.04 0.39 17.62 0 RAGLAND-ANDERSON 47A 1H P-DP 0.0000000 0.0008324 0.0008324 0.0000000 428.36 485.18 3.11 65.50 252.03 212.48 0 RAGLAND-ANDERSON 47B 2H P-DP 0.0000000 0.0008311 0.0008311 0.0000000 588.68 449.47 3.11 65.50 253.40 266.88 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA RAGLAND-ANDERSON 47C 3H P-DP 0.0000000 0.0008311 0.0008311 0.0000000 628.04 423.01 3.11 65.50 224.32 246.72 0 RAINIER 55-1-28 UNIT 1H P-DP 0.0000000 0.0000624 0.0000624 0.0000000 3,168.78 755.53 3.40 65.18 448.29 1,986.66 0 RATHKAMP UNIT 1H P-DP 0.0000000 0.0097130 0.0097130 0.0000000 799.87 166.80 3.58 65.06 158.80 762.42 0 RATHKAMP UNIT 2H P-DP 0.0000000 0.0097130 0.0000000 0.0000000 510.51 126.05 3.58 65.06 126.05 510.51 0 RATHKAMP UNIT 3H P-DP 0.0000000 0.0097130 0.0097130 0.0000000 1,086.85 133.98 3.58 65.06 123.17 896.29 0 RATHKAMP UNIT 4H P-DP 0.0000000 0.0097130 0.0097130 0.0000000 721.44 84.70 3.58 65.06 76.17 545.48 0 REED 24 UNIT 2H P-DP 0.0000000 0.0002962 0.0002962 0.0000000 1,020.73 757.39 3.40 65.18 462.05 732.67 0 REED 24 UNIT 4H P-DP 0.0000000 0.0002962 0.0002962 0.0000000 435.03 263.55 3.40 65.18 166.32 252.73 0 REED 24 UNIT 5H P-DP 0.0000000 0.0002962 0.0002962 0.0000000 1,992.23 803.26 3.40 65.18 438.37 1,108.20 0 REED 24 UNIT 7H P-DP 0.0000000 0.0002962 0.0002962 0.0000000 2,233.87 711.74 3.40 65.18 467.19 1,211.73 0 REED 24 UNIT 8H P-DP 0.0000000 0.0002962 0.0002962 0.0000000 883.01 654.92 3.40 65.18 401.69 601.59 0 REITZ UNIT 5H P-DP 0.0000000 0.0002016 0.0002016 0.0000000 11,286.88 0.00 2.82 64.56 0.00 9,593.54 0 RENDEZVOUS NORTH POOLED UNIT 1LA P-DP 0.0000000 0.0002250 0.0002250 0.0000000 807.42 1,007.91 3.60 65.04 608.53 384.17 0 RENDEZVOUS NORTH POOLED UNIT 9UA P-DP 0.0000000 0.0002250 0.0002250 0.0000000 1,345.90 838.98 3.60 65.04 406.63 583.73 0 RICHARD E LEHMAN SWITZ9BH P-DP 0.0000000 0.0005064 0.0005064 0.0000000 16,089.20 0.00 2.68 64.56 0.00 10,323.20 0 RICHARD E LEHMAN SWITZ9DH P-DP 0.0000000 0.0005064 0.0005064 0.0000000 15,791.04 0.00 2.68 64.56 0.00 11,495.68 0 RICHARD E LEHMAN SWITZ9FH P-DP 0.0000000 0.0005064 0.0005064 0.0000000 22,103.90 0.00 2.68 64.56 0.00 15,360.03 0 RICHARD E LEHMAN SWITZ9HH P-DP 0.0000000 0.0005064 0.0005064 0.0000000 17,638.87 0.00 2.68 64.56 0.00 12,471.93 0 RICHMOND 39 1H P-DP 0.0000000 0.0001197 0.0001197 0.0000000 675.19 81.33 2.38 64.55 81.33 675.19 0 RICHMOND 39 2H P-DP 0.0000000 0.0001197 0.0001197 0.0000000 2,980.73 642.91 2.38 64.55 370.79 1,658.57 0 RICHMOND 39 3H P-DP 0.0000000 0.0001197 0.0001197 0.0000000 2,863.85 508.30 2.38 64.55 282.61 1,389.89 0 RINGNECK DOVE 3 P-DP 0.0000000 0.0031014 0.0031014 0.0000000 6.51 22.18 3.39 66.02 15.58 6.51 0 RIPLEY UNIT 1 P-DP 0.0000000 0.0152740 0.0152740 0.0000000 13.57 1.66 3.60 64.56 1.66 13.57 0 RIPLEY UNIT 3 P-DP 0.0000000 0.0152740 0.0152740 0.0000000 107.28 1.40 3.67 64.56 1.40 107.28 0 RIVER CAT 57-33 A P-DP 0.0000000 0.0013869 0.0013869 0.0000000 839.92 419.19 3.60 65.04 31.74 51.03 0 ROADRUNNER 1 P-DP 0.0000000 0.0035091 0.0035091 0.0000000 110.23 30.51 3.60 65.04 22.28 72.21 0 ROADRUNNER 2 P-DP 0.0000000 0.0035091 0.0035091 0.0000000 91.33 37.79 3.60 65.04 25.27 59.75 0 ROBERT J CITERONI 2 P-DP 0.0000000 0.1100000 0.1100000 0.0000000 23.53 0.00 2.75 64.56 0.00 23.53 0 ROBERT J CITERONI 4 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 21.13 0.00 2.75 64.56 0.00 21.13 0 ROCA UNIT 7 1H P-DP 0.0000000 0.0006594 0.0006594 0.0000000 802.55 466.73 3.60 65.04 332.26 580.56 0 ROCA UNIT 7 2H P-DP 0.0000000 0.0006594 0.0006594 0.0000000 544.53 334.87 3.60 65.04 267.24 363.99 0 ROXY CRC JF 1H P-DP 0.0000000 0.0396138 0.0396138 0.0000000 8,148.24 0.00 3.33 64.56 0.00 5,930.20 0 ROXY N CRC JF 3H P-DP 0.0000000 0.0099981 0.0099981 0.0000000 9,498.76 0.00 3.33 64.56 0.00 7,092.05 0 ROXY NE CRC JF 5H P-DP 0.0000000 0.0034336 0.0034336 0.0000000 9,288.85 0.00 3.33 64.56 0.00 7,259.14 0 SADIE 33-10-4 1H P-DP 0.0000000 0.0704641 0.0704641 0.0000000 10,728.40 1.01 3.19 58.51 1.01 8,112.22 0 SADIE 33-10-4 201H P-DP 0.0000000 0.0704641 0.0704641 0.0000000 11,840.76 2.29 3.19 58.51 2.29 7,865.26 0 SADIE 33-10-4 205H P-DP 0.0000000 0.0082758 0.0082758 0.0000000 14,194.30 0.60 3.19 58.51 0.60 10,410.37 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA SADIE 33-10-4 3H P-DP 0.0000000 0.0306224 0.0306224 0.0000000 12,946.71 4.30 3.19 58.51 4.30 9,864.80 0 SADIE 33-10-4 5H P-DP 0.0000000 0.0309096 0.0309096 0.0000000 12,755.84 1.68 3.19 58.51 1.68 9,253.18 0 SAND DOLLAR UNIT 1 P-DP 0.0000000 0.0032222 0.0032222 0.0000000 35.95 38.44 3.39 66.02 27.47 35.95 0 SANTANA 29 2H P-DP 0.0000000 0.0035482 0.0035482 0.0000000 5,649.95 251.67 2.38 64.55 170.11 3,709.31 0 SHADRACH 68 UNIT 134H P-DP 0.0000000 0.0009551 0.0009551 0.0000000 2,379.08 496.50 2.38 64.55 171.82 495.57 0 SHADRACH 68 UNIT 1H P-DP 0.0000000 0.0009551 0.0009551 0.0000000 4,808.12 688.70 2.38 64.55 361.26 2,240.99 0 SHADRACH 68 UNIT 223H P-DP 0.0000000 0.0009551 0.0009551 0.0000000 3,530.50 662.87 2.38 64.55 209.57 633.01 0 SHADRACH 68 UNIT 2H P-DP 0.0000000 0.0009551 0.0009551 0.0000000 4,378.36 731.20 2.38 64.55 381.57 2,106.13 0 SHADRACH 68 UNIT 324H P-DP 0.0000000 0.0009551 0.0009551 0.0000000 3,052.31 720.06 2.38 64.55 225.84 565.68 0 SHADRACH 68 UNIT 332H P-DP 0.0000000 0.0009551 0.0009551 0.0000000 2,475.95 585.21 2.38 64.55 182.24 461.05 0 SHADRACH MOSES CANTALOUPE 221H P-DP 0.0000000 0.0004688 0.0004688 0.0000000 3,308.63 584.08 2.38 64.55 208.08 705.17 0 SHANNON 210470 3C P-DP 0.0000000 0.0147315 0.0147315 0.0000000 14,308.45 0.00 2.82 64.56 0.00 5,815.66 0 SHANNON 210470 4B P-DP 0.0000000 0.0147315 0.0147315 0.0000000 14,686.88 0.00 2.82 64.56 0.00 5,978.96 0 SHANNON 211271 1B P-DP 0.0000000 0.0147315 0.0147315 0.0000000 13,863.74 0.00 2.82 64.56 0.00 5,837.85 0 SHANNON 211271 2A P-DP 0.0000000 0.0147315 0.0147315 0.0000000 13,750.11 0.00 2.82 64.56 0.00 5,584.70 0 SHINABERRY MILDRED K 1 P-DP 0.0000000 0.0749400 0.0749400 0.0000000 155.92 3.99 3.67 64.56 3.99 116.68 0 SHIRLEY -B- 3815R P-DP 0.0000000 0.0140625 0.0140625 0.0000000 103.01 94.66 3.43 66.60 59.49 63.96 0 SHIRLEY 3806 P-DP 0.0000000 0.0140625 0.0140625 0.0000000 92.34 82.89 3.43 66.60 58.97 68.92 0 SHIRLEY 3807 P-DP 0.0000000 0.0140625 0.0140625 0.0000000 52.70 27.20 3.43 66.60 19.59 39.84 0 SHIRLEY 3808 P-DP 0.0000000 0.0140625 0.0140625 0.0000000 80.34 47.53 3.43 66.60 35.27 54.68 0 SHOSHONE A 34-166-165 5201H P-DP 0.0000000 0.0000010 0.0000010 0.0000000 3,085.04 931.51 3.60 65.04 348.12 1,139.89 0 SIDWELL SE WHL BL 10H P-DP 0.0000000 0.0340845 0.0340845 0.0000000 8,289.79 0.00 2.82 64.56 0.00 4,619.97 0 SIDWELL SE WHL BL 8H P-DP 0.0000000 0.0340845 0.0340845 0.0000000 8,219.49 0.00 2.82 64.56 0.00 4,371.82 0 SIDWELL SW WHL BL 4H P-DP 0.0000000 0.0068418 0.0068418 0.0000000 11,335.30 0.00 2.82 64.56 0.00 9,202.12 0 SIXTEEN PENNY NAIL 310 1LL P-DP 0.0000000 0.0001428 0.0001428 0.0000000 558.17 307.39 3.11 65.50 225.84 436.83 0 SIXTEEN PENNY NAIL 310 2LM P-DP 0.0000000 0.0001434 0.0001434 0.0000000 268.91 176.08 3.11 65.50 136.71 220.64 0 SIXTEEN PENNY NAIL 310 8JM P-DP 0.0000000 0.0001447 0.0001447 0.0000000 1,228.25 314.02 3.11 65.50 139.22 411.30 0 SIXTEEN PENNY NAIL 310A 3LL P-DP 0.0000000 0.0001435 0.0001435 0.0000000 455.89 232.94 3.11 65.50 148.94 317.59 0 SIXTEEN PENNY NAIL 310A 9JM P-DP 0.0000000 0.0001444 0.0001444 0.0000000 705.28 123.65 3.11 65.50 58.20 255.18 0 SIXTEEN PENNY NAIL 310B 10JM P-DP 0.0000000 0.0001447 0.0001447 0.0000000 812.13 125.84 3.11 65.50 53.27 168.88 0 SIXTEEN PENNY NAIL 310B 4LM P-DP 0.0000000 0.0001433 0.0001433 0.0000000 1,125.80 216.89 3.11 65.50 156.49 423.00 0 SIXTEEN PENNY NAIL 310B 5LL P-DP 0.0000000 0.0001434 0.0001434 0.0000000 508.85 250.15 3.11 65.50 176.36 467.72 0 SIXTEEN PENNY NAIL 310C 11JM P-DP 0.0000000 0.0001449 0.0001449 0.0000000 542.02 213.51 3.11 65.50 101.17 202.35 0 SIXTEEN PENNY NAIL 310C 6LM P-DP 0.0000000 0.0001435 0.0001435 0.0000000 951.76 245.87 3.11 65.50 193.11 485.34 0 SIXTEEN PENNY NAIL 310C 7LL P-DP 0.0000000 0.0001427 0.0001427 0.0000000 687.92 228.16 3.11 65.50 201.26 449.52 0 SMASHOSAURUS 1 P-DP 0.0000000 0.0001633 0.0001633 0.0000000 16,170.59 0.00 2.82 64.56 0.00 13,875.19 0 SMASHOSAURUS 3 P-DP 0.0000000 0.0001016 0.0001016 0.0000000 23,385.80 0.00 2.82 64.56 0.00 16,464.59 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA SMASHOSAURUS 5 P-DP 0.0000000 0.0122069 0.0122069 0.0000000 17,811.51 0.00 2.82 64.56 0.00 14,365.62 0 SMASHOSAURUS 7 P-DP 0.0000000 0.0001633 0.0001633 0.0000000 22,476.32 0.00 2.82 64.56 0.00 15,457.61 0 SPIRE 226-34 UNIT 1H P-DP 0.0000000 0.0019335 0.0019335 0.0000000 3,632.30 229.30 3.60 65.04 150.93 2,187.03 0 SPITFIRE 1H P-DP 0.0000000 0.0001648 0.0001648 0.0000000 11,231.35 0.00 2.82 64.56 0.00 9,811.81 0 SPITFIRE 3H P-DP 0.0000000 0.0001648 0.0001648 0.0000000 8,208.81 0.00 2.82 64.56 0.00 7,076.89 0 SRO 551 ALLOC B 101H P-DP 0.0000000 0.0001342 0.0001342 0.0000000 3,377.26 433.55 3.60 65.04 170.09 1,479.71 0 SRO 551 ALLOC. A 100H P-DP 0.0000000 0.0001342 0.0001342 0.0000000 3,106.23 367.79 3.60 65.04 185.09 1,616.14 0 STATE EILAND 3-33 11H P-DP 0.0000000 0.0005021 0.0005021 0.0000000 743.84 304.92 3.60 65.04 304.92 743.84 0 STATE EILAND 6047B-34 51H P-DP 0.0000000 0.0018986 0.0018986 0.0000000 1,451.80 565.12 3.60 65.04 367.36 772.59 0 STATE MUDDY WATERS 30 2H P-DP 0.0000000 0.0025281 0.0025281 0.0000000 3,388.54 239.17 2.38 64.55 181.87 2,421.22 0 STELLA STATE 34-208 WRD UNIT 2H P-DP 0.0000000 0.0002116 0.0002116 0.0000000 1,977.34 307.44 3.60 65.04 156.81 1,189.11 0 STICKLINE 1H P-DP 0.0000000 0.0009551 0.0009551 0.0000000 6,286.69 561.62 3.60 65.04 246.10 2,871.40 0 STONE-GIST W45A 1H P-DP 0.0000000 0.0031123 0.0031123 0.0000000 395.19 466.50 3.25 65.49 238.50 176.37 0 STONE-GIST W45B 2H P-DP 0.0000000 0.0031557 0.0031557 0.0000000 639.41 446.84 3.25 65.49 239.14 226.15 0 STONE-GIST W45C 3H P-DP 0.0000000 0.0031135 0.0031135 0.0000000 1,099.83 565.21 3.25 65.49 253.89 304.70 0 STONE-GIST W45I 9H P-DP 0.0000000 0.0031129 0.0031129 0.0000000 444.13 309.33 3.25 65.49 147.74 124.98 0 STONE-GIST W45J 10H P-DP 0.0000000 0.0031508 0.0031508 0.0000000 632.80 369.27 3.25 65.49 160.55 166.84 0 SUGARLOAF 74 1H P-DP 0.0000000 0.0021897 0.0021897 0.0000000 2,037.84 552.14 2.38 64.55 372.42 1,518.72 0 SUGARLOAF 7475 1U B 1H P-DP 0.0000000 0.0017861 0.0017861 0.0000000 1,522.44 303.22 2.38 64.55 181.02 810.61 0 SUGARLOAF 7475 2U B 2H P-DP 0.0000000 0.0015462 0.0015462 0.0000000 1,344.35 311.73 2.38 64.55 206.62 907.73 0 SUGARLOAF 7475 3U A 3H P-DP 0.0000000 0.0016105 0.0016105 0.0000000 2,843.83 747.06 2.38 64.55 521.44 1,728.86 0 SUGG A 141-140 (ALLOC-A) 1SM P-DP 0.0000000 0.0121102 0.0121102 0.0000000 3,024.95 277.51 2.78 63.92 180.66 1,271.29 0 SUGG A 141-140 (ALLOC-B) 2SU P-DP 0.0000000 0.0128238 0.0128238 0.0000000 2,079.24 184.86 2.78 63.92 121.90 968.47 0 SUGG A 141-140 (ALLOC-C) 3SM P-DP 0.0000000 0.0124861 0.0124861 0.0000000 3,292.79 243.90 2.78 63.92 152.92 1,249.56 0 SUGG A 141-140 (ALLOC-D) 4SU P-DP 0.0000000 0.0122146 0.0122146 0.0000000 2,129.66 168.23 2.78 63.92 127.04 771.17 0 SUGG A 141-140 (ALLOC-E) 5RM P-DP 0.0000000 0.0121537 0.0121537 0.0000000 3,224.95 189.12 2.78 63.92 135.88 1,459.98 0 SUGG A 141-140 (ALLOC-F) 6SM P-DP 0.0000000 0.0121297 0.0121297 0.0000000 2,336.84 94.05 2.78 63.92 74.47 1,279.36 0 SUGG A 141-140 (ALLOC-F) 6SU P-DP 0.0000000 0.0122156 0.0122156 0.0000000 2,064.35 114.45 2.78 63.92 99.58 1,075.08 0 SUGG A 141-140 (ALLOC-G) 7SM P-DP 0.0000000 0.0122500 0.0122500 0.0000000 3,095.34 124.46 2.78 63.92 97.78 1,415.04 0 SUGG A 141-140 (ALLOC-G) 7SU P-DP 0.0000000 0.0123396 0.0123396 0.0000000 3,032.99 109.45 2.78 63.92 90.15 1,424.20 0 SUGG A 141-140 (ALLOC-H) 8SM P-DP 0.0000000 0.0121654 0.0121654 0.0000000 5,176.86 142.00 2.78 63.92 115.96 1,775.51 0 SUGG A 141-140 (ALLOC-H) 8SU P-DP 0.0000000 0.0123361 0.0123361 0.0000000 2,068.72 111.55 2.78 63.92 93.75 1,234.21 0 SUSTR UNIT 1H P-DP 0.0000000 0.0107181 0.0107181 0.0000000 399.04 209.35 3.39 66.02 172.60 310.32 0 TANNER WYN JF 2H P-DP 0.0000000 0.1162524 0.1162524 0.0000000 11,755.54 0.00 3.33 64.56 0.00 9,841.16 0 TANNER WYN JF 4H P-DP 0.0000000 0.1162524 0.1162524 0.0000000 14,440.01 0.00 3.33 64.56 0.00 10,989.37 0 TARGAC UNIT 1H P-DP 0.0000000 0.0235042 0.0235042 0.0000000 314.04 182.87 3.39 66.02 153.49 272.68 0 TEEWINOT NORTH UNIT 4LA P-DP 0.0000000 0.0004880 0.0004880 0.0000000 480.31 442.29 3.60 65.04 316.58 375.36 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TEEWINOT SOUTH UNIT 5LA P-DP 0.0000000 0.0004880 0.0004880 0.0000000 1,016.98 830.72 3.60 65.04 505.06 602.26 0 THOMPSON E SMF JF 5H P-DP 0.0000000 0.0005497 0.0005497 0.0000000 11,021.65 0.00 3.33 64.56 0.00 7,948.92 0 THOMPSON W SMF JF 1H P-DP 0.0000000 0.0075886 0.0075886 0.0000000 12,061.39 0.00 3.33 64.56 0.00 8,566.75 0 THOMPSON W SMF JF 3H P-DP 0.0000000 0.0075886 0.0075886 0.0000000 11,673.22 0.00 3.33 64.56 0.00 8,312.36 0 THORPE 1-74 LOV 2H P-DP 0.0000000 0.0000797 0.0000797 0.0000000 407.86 58.93 3.40 65.18 39.44 370.27 0 THORPE 1-74 LOV 3H P-DP 0.0000000 0.0000797 0.0000797 0.0000000 885.11 406.73 3.40 65.18 300.44 666.57 0 THORPE 1-74 LOV 4H P-DP 0.0000000 0.0001593 0.0001593 0.0000000 553.52 336.11 3.40 65.18 244.79 345.62 0 THURMOND 132 ALLOC C 11H P-DP 0.0000000 0.0015190 0.0015190 0.0000000 3,079.25 303.84 2.38 64.55 136.08 1,271.45 0 THURMOND A137 ALLOC. A 10H P-DP 0.0000000 0.0014494 0.0014494 0.0000000 2,839.87 432.55 2.38 64.55 220.81 1,263.97 0 TIGER 210187 2A P-DP 0.0000000 0.0028920 0.0028920 0.0000000 10,823.93 0.00 2.82 64.56 0.00 8,136.80 0 TIGER 210187 3C P-DP 0.0000000 0.0028920 0.0028920 0.0000000 9,373.26 0.00 2.82 64.56 0.00 7,693.66 0 TIGER 210187 5B P-DP 0.0000000 0.0028920 0.0028920 0.0000000 8,180.88 0.00 2.82 64.56 0.00 6,590.02 0 TIGER 210475 4C P-DP 0.0000000 0.0000077 0.0000077 0.0000000 9,260.66 0.00 2.82 64.56 0.00 7,002.15 0 TIGER 210476 1A P-DP 0.0000000 0.0028516 0.0028516 0.0000000 10,704.25 0.00 2.82 64.56 0.00 8,097.92 0 TIMMERMAN J1 2208MH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 567.17 439.70 3.43 66.60 268.34 289.16 0 TIMMERMAN J10 2206LH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 927.21 643.04 3.43 66.60 353.02 397.61 0 TIMMERMAN J11 2206BH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 1,758.22 523.12 3.43 66.60 265.06 719.18 0 TIMMERMAN J2 2208LH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 735.66 479.49 3.43 66.60 277.59 322.75 0 TIMMERMAN J3 2208BH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 1,342.88 411.38 3.43 66.60 236.45 635.55 0 TIMMERMAN J4 2207MH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 1,290.18 613.77 3.43 66.60 314.74 451.23 0 TIMMERMAN J5 2207LH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 1,114.45 491.80 3.43 66.60 293.18 479.17 0 TIMMERMAN J6 2207BH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 1,323.15 365.29 3.43 66.60 227.95 685.77 0 TIMMERMAN J7 2217LH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 955.84 440.73 3.43 66.60 260.49 389.31 0 TIMMERMAN J8 2207CH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 1,454.50 226.68 3.43 66.60 125.58 618.04 0 TIMMERMAN J9 2206MH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 1,312.83 787.53 3.43 66.60 448.11 531.49 0 TIN STAR A L 33H P-DP 0.0000000 0.0002979 0.0002979 0.0000000 5,074.24 817.81 2.38 64.55 401.38 2,778.62 0 TIN STAR B L 42H P-DP 0.0000000 0.0002462 0.0002462 0.0000000 3,330.91 420.43 2.38 64.55 259.90 1,979.35 0 TIN STAR D U 46H P-DP 0.0000000 0.0002933 0.0002933 0.0000000 4,902.65 548.25 2.38 64.55 337.37 3,096.71 0 TIPI CHAPMAN 34-163 1H P-DP 0.0000000 0.0000016 0.0000016 0.0000000 594.00 312.21 3.60 65.04 228.22 416.44 0 TIPI CHAPMAN 34-163 2H P-DP 0.0000000 0.0000016 0.0000016 0.0000000 389.38 369.62 3.60 65.04 267.39 305.53 0 TIPI CHAPMAN 34-163 3H P-DP 0.0000000 0.0000016 0.0000016 0.0000000 782.29 177.07 3.60 65.04 132.97 620.08 0 TIPI CHAPMAN 34-163 4H P-DP 0.0000000 0.0000016 0.0000016 0.0000000 1,093.10 587.63 3.60 65.04 419.21 926.61 0 TITO'S 31-42 1LS P-DP 0.0000000 0.0007168 0.0007168 0.0000000 469.65 461.48 3.11 65.50 365.83 230.09 0 TITO'S 31-42 1WA P-DP 0.0000000 0.0007168 0.0007168 0.0000000 455.90 480.88 3.11 65.50 381.67 250.84 0 TITO'S 31-42 1WB P-DP 0.0000000 0.0007168 0.0007168 0.0000000 363.35 396.74 3.11 65.50 306.98 193.78 0 TITO'S 31-42 2LS P-DP 0.0000000 0.0007168 0.0007168 0.0000000 349.23 399.06 3.11 65.50 242.26 163.27 0 TITO'S 31-42 2WA P-DP 0.0000000 0.0007168 0.0007168 0.0000000 2,204.79 171.18 3.11 65.50 111.59 915.14 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TITO'S 31-42 2WB P-DP 0.0000000 0.0007168 0.0007168 0.0000000 432.40 274.82 3.11 65.50 138.86 220.91 0 TITO'S 31-42 3WA P-DP 0.0000000 0.0007168 0.0007168 0.0000000 148.34 400.05 3.11 65.50 213.96 68.45 0 TOWNSEN 1 P-DP 0.0000000 0.0006926 0.0006926 0.0000000 5,736.98 682.01 2.38 64.55 390.85 2,986.78 0 TRAUBE 1-11 WRD 1H P-DP 0.0000000 0.0002124 0.0002124 0.0000000 818.35 640.06 3.60 65.04 513.68 696.50 0 TRAUBE 1-11 WRD 2H P-DP 0.0000000 0.0002124 0.0002124 0.0000000 816.64 371.09 3.60 65.04 251.35 511.74 0 TREE FROG 47 EAST A 1LS P-DP 0.0000000 0.0010000 0.0010000 0.0000000 756.87 335.57 3.39 66.02 274.82 419.56 0 TREE FROG 47 EAST A 1WA P-DP 0.0000000 0.0010055 0.0010055 0.0000000 789.27 665.84 3.39 66.02 477.58 419.47 0 TREE FROG 47 EAST C 3LS P-DP 0.0000000 0.0009949 0.0009949 0.0000000 675.97 274.08 3.39 66.02 206.34 369.34 0 TREE FROG 47 EAST C 3WA P-DP 0.0000000 0.0009948 0.0009948 0.0000000 1,432.43 580.60 3.39 66.02 263.42 375.73 0 TREE FROG 47 EAST C 3WB P-DP 0.0000000 0.0009963 0.0009963 0.0000000 629.40 266.86 3.39 66.02 173.32 324.07 0 TREE FROG 47 WEST UNIT #7MS P-DP 0.0000000 0.0019838 0.0019838 0.0000000 1,443.05 691.85 3.39 66.02 142.67 103.29 0 TREE FROG 47 WEST UNIT 5LS P-DP 0.0000000 0.0010396 0.0010396 0.0000000 724.60 428.97 3.39 66.02 265.61 316.02 0 TREE FROG 47 WEST UNIT 5WA P-DP 0.0000000 0.0010396 0.0010396 0.0000000 971.41 575.19 3.39 66.02 335.97 432.22 0 TREE FROG 47 WEST UNIT 5WB P-DP 0.0000000 0.0010396 0.0010396 0.0000000 808.94 431.71 3.39 66.02 229.71 316.77 0 TREE FROG 47 WEST UNIT 7LS P-DP 0.0000000 0.0019838 0.0019838 0.0000000 958.14 525.75 3.39 66.02 137.35 101.01 0 TREE FROG 47 WEST UNIT 7WA P-DP 0.0000000 0.0019838 0.0019838 0.0000000 1,470.21 343.15 3.39 66.02 100.67 162.76 0 TRIANGLE 75 2H P-DP 0.0000000 0.0008994 0.0008994 0.0000000 1,180.26 221.34 2.38 64.55 162.74 836.95 0 TRIDACNA 34-208 WRD UNIT 1H P-DP 0.0000000 0.0001060 0.0001060 0.0000000 2,628.06 413.47 3.60 65.04 229.02 1,541.81 0 TRIDACNA 34-208 WRD UNIT 2H P-DP 0.0000000 0.0001060 0.0001060 0.0000000 2,384.70 326.79 3.60 65.04 219.27 1,450.89 0 TRIDACNA 34-208 WRD UNIT 3H P-DP 0.0000000 0.0001060 0.0001060 0.0000000 2,381.78 394.82 3.60 65.04 246.42 1,615.50 0 TROTT 34-183 1H P-DP 0.0000000 0.0000983 0.0000983 0.0000000 761.32 89.47 3.60 65.04 45.35 431.51 0 TUMBLEWEED 34-170 UNIT 1H P-DP 0.0000000 0.0000183 0.0000183 0.0000000 1,111.60 690.94 3.60 65.04 296.88 450.94 0 UNDERWOOD 34-138 UNIT 1H P-DP 0.0000000 0.0001953 0.0001953 0.0000000 357.40 257.43 3.60 65.04 177.33 233.68 0 VALERIE 210473 1A P-DP 0.0000000 0.0083562 0.0083562 0.0000000 10,350.87 0.00 2.82 64.56 0.00 8,851.64 0 VALERIE 210473 2B P-DP 0.0000000 0.0083562 0.0083562 0.0000000 10,850.41 0.00 2.82 64.56 0.00 9,297.56 0 VALERIE 210473 4C P-DP 0.0000000 0.0083562 0.0083562 0.0000000 12,606.10 0.00 2.82 64.56 0.00 10,308.11 0 VICKERS '34-127' 1H P-DP 0.0000000 0.0004386 0.0004386 0.0000000 497.39 221.72 3.60 65.04 185.06 366.91 0 VICKERS '34-127' 2H P-DP 0.0000000 0.0004386 0.0004386 0.0000000 224.58 168.40 3.60 65.04 121.39 162.14 0 WARD 18CC 1804D P-DP 0.0000000 0.0015893 0.0015893 0.0000000 657.10 464.62 3.39 66.02 313.07 376.74 0 WARD 18D 1803D P-DP 0.0000000 0.0015893 0.0015893 0.0000000 509.82 496.45 3.39 66.02 359.65 390.59 0 WARREN DUNLAP 1 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 10.50 0.00 2.75 64.56 0.00 10.50 0 WHIRLAWAY 99 1HA P-DP 0.0000000 0.0002250 0.0002250 0.0000000 174.44 348.15 3.60 65.04 233.53 138.38 0 WHISKEY RIVER 9596A-34 11H P-DP 0.0000000 0.0000059 0.0000059 0.0000000 937.32 825.36 3.60 65.04 365.56 452.84 0 WHISKEY RIVER 9596A-34 12H P-DP 0.0000000 0.0000055 0.0000055 0.0000000 519.35 240.10 3.60 65.04 153.98 297.43 0 WHISKEY RIVER 9596A-34 13H P-DP 0.0000000 0.0000056 0.0000056 0.0000000 366.89 269.63 3.60 65.04 218.28 218.11 0 WHISKEY RIVER 9596B-34 1H P-DP 0.0000000 0.0000056 0.0000056 0.0000000 434.33 525.05 3.60 65.04 276.78 292.60 0 WHISKEY RIVER 9596B-34 31H P-DP 0.0000000 0.0000056 0.0000056 0.0000000 559.25 361.39 3.60 65.04 203.79 313.71 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA WHISKEY RIVER 9596B-34 32H P-DP 0.0000000 0.0000056 0.0000056 0.0000000 1,187.93 431.21 3.60 65.04 238.43 527.46 0 WHISKEY RIVER 9596C-34 1H P-DP 0.0000000 0.0000056 0.0000056 0.0000000 911.04 726.37 3.60 65.04 295.00 358.81 0 WHISKEY RIVER 9596D-34 81H P-DP 0.0000000 0.0000056 0.0000056 0.0000000 1,246.26 686.59 3.60 65.04 364.65 460.28 0 WHITLEY 34-231 1H P-DP 0.0000000 0.0007275 0.0007275 0.0000000 210.10 30.70 3.60 65.04 30.70 210.10 0 WILLETT POT STILL 5-2C UNIT 1H P-DP 0.0000000 0.0033416 0.0033416 0.0000000 2,916.74 322.08 2.38 64.55 183.79 1,610.38 0 WILLIE THE WILDCAT 3-15 A P-DP 0.0000000 0.0004136 0.0004136 0.0000000 1,938.11 703.88 3.11 65.50 262.47 402.08 0 WILLIE THE WILDCAT 3-15 A P-DP 0.0000000 0.0004136 0.0004136 0.0000000 973.20 395.91 3.11 65.50 125.47 202.49 0 WILLIE THE WILDCAT 3-15 A P-DP 0.0000000 0.0004136 0.0004136 0.0000000 806.99 342.34 3.11 65.50 108.52 162.78 0 WILLIE THE WILDCAT 3-15 B P-DP 0.0000000 0.0004136 0.0004136 0.0000000 1,342.98 573.83 3.11 65.50 208.78 304.72 0 WILLIE THE WILDCAT 3-15 B P-DP 0.0000000 0.0004136 0.0004136 0.0000000 1,141.05 558.77 3.11 65.50 180.93 246.58 0 WILLIE THE WILDCAT 3-15 B P-DP 0.0000000 0.0004136 0.0004136 0.0000000 1,175.29 538.95 3.11 65.50 195.27 272.11 0 WILLIE THE WILDCAT 3-15 B 2WB P-DP 0.0000000 0.0004136 0.0004136 0.0000000 2,552.48 698.32 3.11 65.50 262.01 556.57 0 WILLIE THE WILDCAT 3-15 C P-DP 0.0000000 0.0004136 0.0004136 0.0000000 1,709.44 551.15 3.11 65.50 205.03 360.58 0 WILLIE THE WILDCAT 3-15 C P-DP 0.0000000 0.0004136 0.0004136 0.0000000 911.22 360.61 3.11 65.50 119.93 183.43 0 WILLIE THE WILDCAT 3-15 D P-DP 0.0000000 0.0004136 0.0004136 0.0000000 1,400.66 472.32 3.11 65.50 109.98 209.49 0 WILLIE THE WILDCAT 3-15 D P-DP 0.0000000 0.0004136 0.0004136 0.0000000 1,370.38 355.19 3.11 65.50 78.73 200.11 0 WILLIE THE WILDCAT 3-15 D 5JD P-DP 0.0000000 0.0004136 0.0004136 0.0000000 629.62 302.44 3.11 65.50 115.72 173.67 0 WILLIE THE WILDCAT 3-15 D 6LS P-DP 0.0000000 0.0004136 0.0004136 0.0000000 1,056.00 469.72 3.11 65.50 180.39 296.14 0 WILLIE THE WILDCAT 3-15 E P-DP 0.0000000 0.0004136 0.0004136 0.0000000 2,108.36 954.39 3.11 65.50 314.68 400.57 0 WILLIE THE WILDCAT 3-15 E P-DP 0.0000000 0.0004136 0.0004136 0.0000000 963.61 350.23 3.11 65.50 115.72 179.05 0 WILLIE THE WILDCAT 3-15 E P-DP 0.0000000 0.0004136 0.0004136 0.0000000 66.08 59.86 3.11 65.50 20.93 14.23 0 WILLOW LAKES 19 191H P-DP 0.0000000 0.0002451 0.0002451 0.0000000 917.25 308.16 3.43 66.60 191.01 517.86 0 WILSON 184-185 UNIT 2H P-DP 0.0000000 0.0001883 0.0001883 0.0000000 7,393.26 684.62 3.60 65.04 340.96 3,830.18 0 WINDY MOUNTAIN 7879 1U B 1H P-DP 0.0000000 0.0001809 0.0001809 0.0000000 3,025.65 374.99 2.38 64.55 217.15 1,762.59 0 WINDY MOUNTAIN 7879 2U B 2H P-DP 0.0000000 0.0001797 0.0001797 0.0000000 3,507.76 515.59 2.38 64.55 266.67 1,750.51 0 WRIGHT 1-22 E WRD UNIT 2H P-DP 0.0000000 0.0001410 0.0001410 0.0000000 308.61 193.27 3.60 65.04 117.66 190.57 0 WRIGHT 1-22 W WRD UNIT 2H P-DP 0.0000000 0.0001410 0.0001410 0.0000000 346.44 205.59 3.60 65.04 124.25 200.82 0 WRIGHT 1-22E WRD 1H P-DP 0.0000000 0.0001410 0.0001410 0.0000000 423.12 226.91 3.60 65.04 183.84 319.29 0 WRIGHT 1-22W WRD 1H P-DP 0.0000000 0.0001410 0.0001410 0.0000000 206.45 156.74 3.40 65.18 156.23 205.96 0 XBC-CAROLINE 3B 302H P-DP 0.0000000 0.0006273 0.0006273 0.0000000 2,038.57 673.63 3.07 65.64 312.87 558.13 0 XBC-CAROLINE 3C 303H P-DP 0.0000000 0.0006275 0.0006275 0.0000000 1,554.90 524.64 3.07 65.64 274.41 529.66 0 XBC-CAROLINE 3K 311H P-DP 0.0000000 0.0006350 0.0006350 0.0000000 1,796.27 562.63 3.07 65.64 278.73 604.45 0 XBC-CAROLINE 3L 312H P-DP 0.0000000 0.0006470 0.0006470 0.0000000 1,579.58 560.58 3.07 65.64 268.61 575.96 0 XBC-CAROLINE 3M 313H P-DP 0.0000000 0.0006438 0.0006438 0.0000000 1,502.35 558.85 3.07 65.64 270.88 533.67 0 XBC-UNRUH 3A 16H P-DP 0.0000000 0.0006519 0.0006519 0.0000000 1,617.73 743.21 3.07 65.64 338.24 611.39 0 XBC-UNRUH 3B 17H P-DP 0.0000000 0.0006606 0.0006606 0.0000000 2,314.91 574.31 3.07 65.64 314.77 802.03 0 YANKEE 210475 5A P-DP 0.0000000 0.0000077 0.0000077 0.0000000 10,930.14 0.00 2.82 64.56 0.00 8,107.36 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA YELLOW ROSE A UNIT 1H P-DP 0.0000000 0.0001586 0.0001586 0.0000000 851.26 614.05 3.40 65.18 426.44 529.66 0 YELLOW ROSE A UNIT 2H P-DP 0.0000000 0.0001586 0.0001586 0.0000000 1,070.28 690.75 3.40 65.18 403.60 570.01 0 YELLOW ROSE A UNIT 3H P-DP 0.0000000 0.0001586 0.0001586 0.0000000 1,559.49 498.41 3.40 65.18 357.74 1,254.51 0 YELLOW ROSE B UNIT 1H P-DP 0.0000000 0.0001586 0.0001586 0.0000000 1,496.24 661.48 3.40 65.18 340.99 665.47 0 YELLOW ROSE B UNIT 2H P-DP 0.0000000 0.0001586 0.0001586 0.0000000 227.89 326.13 3.40 65.18 185.17 208.80 0 YELLOW ROSE B UNIT 3H P-DP 0.0000000 0.0001586 0.0001586 0.0000000 2,667.19 818.82 3.40 65.18 398.63 1,206.29 0 243,471.21 2,579,253.73 128,528.61 1,638,516.52 Proved Behind Pipe Rsv Class & Category HALL-PORTER 'C' 621-596 231 P-BP 0.0000000 0.0014830 0.0014830 0.0000000 997.06 364.91 3.43 66.60 0.00 0.00 0 HALL-PORTER `B` 621-596 #123 P-BP 0.0000000 0.0014830 0.0014830 0.0000000 1,967.81 508.42 3.43 66.60 0.00 0.00 0 KODIAK 7677 1U B 1H P-BP 0.0000000 0.0006487 0.0006487 0.0000000 3,976.69 647.57 2.38 64.55 0.00 0.00 0 KODIAK 7677 2U B 2H P-BP 0.0000000 0.0006487 0.0006487 0.0000000 4,023.77 655.24 2.38 64.55 0.00 0.00 0 KODIAK 7677 3U A 3H P-BP 0.0000000 0.0006487 0.0006487 0.0000000 4,083.84 643.39 2.38 64.55 0.00 0.00 0 KODIAK 7677 4U A 4H P-BP 0.0000000 0.0006487 0.0006487 0.0000000 4,052.44 638.43 2.38 64.55 0.00 0.00 0 MARY GRACE 201-202 UNIT 2H P-BP 0.0000000 0.0001950 0.0001950 0.0000000 2,675.48 455.13 3.60 65.04 22.69 122.16 0 Mud Hen 5 P-BP 0.0000000 0.0005049 0.0005049 0.0000000 3,183.03 1,263.87 3.60 65.04 0.00 0.00 0 NORRIS UNIT 32-H #3332SH P-BP 0.0000000 0.0045833 0.0045833 0.0000000 1,902.59 491.66 3.11 65.50 0.00 0.00 0 NORRIS UNIT 32-H #3333SH P-BP 0.0000000 0.0045833 0.0045833 0.0000000 1,931.69 499.14 3.11 65.50 0.00 0.00 0 NORRIS-MIMS ALLOCATION #3335SH P-BP 0.0000000 0.0045833 0.0045833 0.0000000 2,191.50 565.95 3.11 65.50 0.00 0.00 0 TITOS 31-42 #U 1WB P-BP 0.0000000 0.0007896 0.0007896 0.0000000 1,019.90 451.64 3.11 65.50 0.00 0.00 0 TREE FROG 47 WEST UNIT #7WB P-BP 0.0000000 0.0019838 0.0019838 0.0000000 1,551.66 535.43 3.39 66.02 0.00 0.00 0 7,720.76 33,557.47 22.69 122.16 Proved Shut-In Rsv Class & Category ALLMAN 24 6H P-SI 0.0000000 0.0043022 0.0000000 0.0000000 1,867.07 149.18 2.38 64.55 149.18 1,867.07 0 AVARY 1 P-SI 0.0000000 0.1234560 0.0000000 0.0000000 238.51 31.24 3.60 65.04 31.24 238.51 0 AVARY 10 P-SI 0.0000000 0.1234560 0.0000000 0.0000000 139.14 20.26 3.60 65.04 20.26 139.14 0 AVARY 11 P-SI 0.0000000 0.1234560 0.0000000 0.0000000 189.42 36.57 3.60 65.04 36.57 189.42 0 AVARY 12 P-SI 0.0000000 0.1234560 0.0000000 0.0000000 210.26 26.22 3.60 65.04 26.22 210.26 0 AVARY 14 P-SI 0.0000000 0.1234560 0.0000000 0.0000000 1,771.62 158.46 3.60 65.04 158.46 1,771.62 0 AVARY 15 P-SI 0.0000000 0.1234560 0.0000000 0.0000000 1,790.08 184.50 3.60 65.04 184.50 1,790.08 0 AVARY 16 P-SI 0.0000000 0.1234560 0.0000000 0.0000000 1,464.28 128.53 3.60 65.04 128.53 1,464.28 0 AVARY 17 P-SI 0.0000000 0.1234560 0.0000000 0.0000000 209.07 130.74 3.60 65.04 130.74 209.07 0 AVARY 2 P-SI 0.0000000 0.1234560 0.0000000 0.0000000 236.07 41.08 3.60 65.04 41.08 236.07 0 AVARY 3 P-SI 0.0000000 0.1234560 0.0000000 0.0000000 141.27 19.37 3.60 65.04 19.37 141.27 0 AVARY 4 P-SI 0.0000000 0.1234560 0.0000000 0.0000000 338.24 43.25 3.60 65.04 43.25 338.24 0 AVARY 5 P-SI 0.0000000 0.1234560 0.0000000 0.0000000 376.48 39.73 3.60 65.04 39.73 376.48 0 AVARY 6 P-SI 0.0000000 0.1234560 0.0000000 0.0000000 203.94 28.62 3.60 65.04 28.62 203.94 0 TABLE 9

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2022 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA AVARY 7 P-SI 0.0000000 0.1234560 0.0000000 0.0000000 312.63 43.23 3.60 65.04 43.23 312.63 0 AVARY 8 P-SI 0.0000000 0.1234560 0.0000000 0.0000000 139.14 20.26 3.60 65.04 20.26 139.14 0 AVARY 9 P-SI 0.0000000 0.1234560 0.0000000 0.0000000 1,464.28 128.50 3.60 65.04 128.50 1,464.28 0 AVARY, G. Q. 1 P-SI 0.0000000 0.1234560 0.0000000 0.0000000 181.61 113.37 3.60 65.04 113.37 181.61 0 AVARY, G. Q. 2 P-SI 0.0000000 0.1234560 0.0000000 0.0000000 339.75 168.19 3.60 65.04 168.19 339.75 0 BLACK STONE 34-216 1H P-SI 0.0000000 0.0009146 0.0000000 0.0000000 290.52 45.59 3.60 65.04 45.59 290.52 0 BRUNSON '15' 1 P-SI 0.0000000 0.0001586 0.0000000 0.0000000 51.92 0.34 3.40 65.18 0.34 51.92 0 BYRD 34-170 UNIT 1H P-SI 0.0000000 0.0002000 0.0002000 0.0000000 211.95 121.16 3.60 65.04 121.16 211.95 0 BYRD 34-170 UNIT 2H P-SI 0.0000000 0.0002000 0.0002000 0.0000000 193.44 129.07 3.60 65.04 129.07 193.44 0 GATLIN, MARY 2006H P-SI 0.0000000 0.0008036 0.0000000 0.0000000 520.07 13.24 3.43 66.60 13.24 520.07 0 HA RA SUA;WIGGINS 36-15-10 H 001 P-SI 0.0000000 0.0493230 0.0493230 0.0000000 425.35 0.02 3.17 64.56 0.02 425.35 0 HERMOSA 1 P-SI 0.0000000 0.0014400 0.0014400 0.0000000 1,702.20 0.63 2.38 64.55 0.63 1,702.20 0 HERMOSA UNIT 2 1 P-SI 0.0000000 0.0000949 0.0000949 0.0000000 2,690.58 0.56 2.38 64.55 0.56 2,690.58 0 HOLY GRAIL 43 1 P-SI 0.0000000 0.0035264 0.0000000 0.0000000 38.56 20.03 3.39 66.02 20.03 38.56 0 JANAK UNIT 1H P-SI 0.0000000 0.0251620 0.0000000 0.0000000 506.21 96.58 3.58 65.06 96.58 506.21 0 LANE, ROWENA 11D P-SI 0.0000000 0.0014351 0.0000000 0.0000000 0.00 0.00 3.39 66.02 0.00 0.00 0 LANE, ROWENA 11D P-SI 0.0000000 0.0014351 0.0000000 0.0000000 0.00 0.00 3.39 66.02 0.00 0.00 0 NORTH AMERICAN COAL 1 P-SI 0.0000000 0.0560430 0.0000000 0.0000000 21.39 0.18 3.67 64.56 0.18 21.39 0 NORTH AMERICAN COAL 1-3 P-SI 0.0000000 0.1000000 0.1000000 0.0000000 13.45 0.14 3.33 64.56 0.14 13.45 0 PARKS FIELD UNIT NO. 2 1929 P-SI 0.0000000 0.0008036 0.0000000 0.0000000 3,221.09 64.76 3.43 66.60 64.76 3,221.09 0 PARKS FIELD UNIT NO. 2 904H P-SI 0.0000000 0.0008036 0.0000000 0.0000000 7,833.36 222.95 3.43 66.60 222.95 7,833.36 0 PARTAGAS 37 1 P-SI 0.0000000 0.0031250 0.0000000 0.0000000 10.32 5.41 3.39 66.02 5.41 10.32 0 QUITO, S. W. (DELAWARE) UNIT 702 P-SI 0.0000000 0.0002557 0.0002557 0.0000000 1.25 1.06 3.60 65.04 0.66 1.25 0 RICHAR BLAZEK 2 P-SI 0.0000000 0.1100000 0.0000000 0.0000000 0.00 0.00 2.75 64.56 0.00 0.00 0 STELLA STATE 34-208 WRD UNIT 1H P-SI 0.0000000 0.0002116 0.0000000 0.0000000 970.56 121.24 3.60 65.04 121.24 970.56 0 THORPE 1-74 LOV 1H P-SI 0.0000000 0.0001593 0.0001593 0.0000000 175.09 80.40 3.40 65.18 80.40 175.09 0 U. S. NATIONAL 2 P-SI 0.0000000 0.1234560 0.1234560 0.0000000 7,797.08 0.04 3.60 65.04 0.04 7,797.08 0 WHITLEY 34-231 2H P-SI 0.0000000 0.0007275 0.0000000 0.0000000 164.80 7.87 3.60 65.04 7.87 164.80 0 2,442.55 38,452.00 2,442.15 38,452.00 Proved Undeveloped Rsv Class & Category DAVIS 201-200-199 UNIT 2H P-UD 0.0000000 0.0002820 0.0002820 0.0000000 5,322.55 659.27 3.60 65.04 0.00 0.00 0 RAINIER 55-1-28 UNIT 5H P-UD 0.0000000 0.0000624 0.0000624 0.0000000 2,962.44 517.86 3.40 65.18 0.00 0.00 0 1,177.13 8,284.99 0.00 0.00 Proved P&A Rsv Class & Category HOLY GRAIL 43 A 2 P-PA 0.0000000 0.0035275 0.0035275 0.0000000 155.52 63.57 3.39 66.02 63.57 155.52 0 63.57 155.52 63.57 155.52 Grand Total 254,875.23 2,659,703.71 131,057.02 1,677,246.20 TABLE 9


Name			Incorporation
America Lignite Energy LLC			Delaware (50%)
Bellaire Corporation			Ohio
C&H Mining Company, Inc.			Alabama
Caddo Creek Resources Company, LLC			Nevada
Camino Real Fuels, LLC			Nevada
Catapult Mineral Partners, LLC			Nevada
Centennial Natural Resources, LLC			Nevada
Coyote Creek Mining Company, LLC			Nevada
Demery Resources Company, LLC			Nevada
The Coteau Properties Company			Ohio
The Falkirk Mining Company			Ohio
GRENAC, LLC			Delaware (50%)
Liberty Fuels Company, LLC			Nevada
Mississippi Lignite Mining Company			Texas
Mitigation Resources of North America, LLC			Nevada
Mitigate Alabama, LLC			Nevada
Mitigate Tennessee, LLC			Nevada
Mitigate Texas, LLC			Nevada
NAM - CMX, LLC			Nevada
NAM - Corkscrew, LLC			Nevada
NAM - CSA, LLC			Nevada
NAM - IND, LLC			Nevada
NAM - Little River, LLC			Nevada
NAM - MCA, LLC			Nevada
NAM - Newberry, LLC			Nevada
NAM - PBA, LLC			Nevada
NAM - Pasco, LLC			Nevada
NAM - Perry, LLC			Nevada
NAM - QueenField, LLC			Nevada
NAM - Rosser, LLC			Nevada
NAM - SACC, LLC			Nevada
NAM - SDI, LLC			Nevada
NAM - WFA, LLC			Nevada
NAM - WRQ, LLC			Nevada
NAM - 7D, LLC			Nevada
NoDak Energy Investments Corporation			Nevada
The North American Coal Corporation			Delaware
North American Coal Corporation India Private Limited			India
North American Mining, LLC			Nevada
North American Coal Royalty Company			Delaware
Otter Creek Mining Company LLC			Nevada
Red Hills Property Company LLC			Mississippi
The Sabine Mining Company			Nevada
Sawtooth Mining, LLC			Nevada
Trident Technology Services Group, LLC			Nevada
Trifecta Renewable Solutions, LLC			Delaware
TRU Global Energy Services, LLC			Delaware
TRU Energy Services, LLC			Nevada
Reed Minerals, Inc.			Alabama
Yockanookany Mitigation Resources, LLC			Nevada


/s/ Richard de J. Osborne						February 23, 2022
Richard de J. Osborne						Date


/s/ Alfred M. Rankin, Jr.						February 23, 2022
Alfred M. Rankin, Jr.						Date


Name of Mine or Quarry (1)	Mine Act Section 104 Significant & Substantial Citations (2)(3)	Mine Act Section 104(d) Citations	Total Dollar Value of Proposed MSHA Assessment		Number of Legal Actions Initiated before the FMSHRC for the year ended at December 31, 2021	Number of Legal Actions Resolved before the FMSHRC for the year ended at December 31, 2021	Number of Legal Actions Pending before the FMSHRC at December 31, 2021
Coteau (Freedom Mine)	—	—	$	250	—	—	—
Falkirk (Falkirk Mine)	1	—	1,284		—	—	—
Sabine (South Hallsville No. 1 Mine)	1	—	636		—	—	—
Demery (Five Forks Mine)	—	—	—		—	—	—
Caddo Creek (Marshall Mine)	—	—	133		—	—	—
Coyote Creek (Coyote Creek Mine)	—	—	125		—	—	—
Bisti Fuels (Navajo Mine) (4)	2	—	2,034		—	—	—
MLMC (Red Hills Mine)	—	—	—		—	—	—
North American Mining Operations:	—	—	—		—	—	—
Alico Quarry
Card Sound Quarry	—		—		—	—	—
Center Hill Quarry	—		—		—	—	—
FEC Quarry	—		929		—	—	—
Inglis Quarry	—		—
Krome Quarry	1		2,558		—	—	—
SCL Quarry	—	—	—		—	—	—
St. Catherine Quarry	—	—	—		—	—	—
Seven Diamonds Quarry	—	—	—		—	—	—
Central State Aggregates Quarry	—	—	—		—	—	—
Johnson County Quarry	—	—	—		—	—	—
Little River Quarry	—	—	—		—	—	—
Mid Coast Aggregates Quarry	—		—		—	—	—
Newberry Quarry	—	—	—		—	—	—
County Line Quarry	—	—	—		—	—	—
Palm Beach Aggregates Quarry	—	—	279		—	—	—
Perry Quarry	—	—	—		—	—	—
Queensfield Mine	—	—	—		—	—	—
Rosser Quarry	—	—	202		—	—	—
SDI Aggregates Quarry	—	—	—		—	—	—
West Florida Aggregates Quarry	—	—	146		—	—	—
Titan Corkscrew Quarry	—	—	—		—	—	—
White Rock Quarry - North	1	—	1,307		—	—	—
Total	6	—	9,883		—	—	—


As of 1/1/2022 Net Reserves Sales Volumes
	Oil &	Wet		Residue		NPV
	Condensate	Gas	NGL	Gas	FNI	Disc. @ 10%
Reserve Class/Cat	(bbl)	(Mcf)	(bbl)	(Mcf)	($)	($)
Proved Producing	155,180	17,308,430	278,180	16,586,320	55,826,520	36,295,500
Proved Behind Pipe	12,250	48,470	4,050	31,040	893,000	533,570
Proved Shut-In	-	-	-	-	-	-
Proved Undeveloped	220	1,690	90	1,210	17,590	9,970
Proved P&A	-	-	-	-	-	-
Total Proved	167,650	17,358,590	282,320	16,618,570	56,737,110	36,839,040


Appendix A Definitions of Oil and Gas Reserves - Securities and Exchange Commission