CRGY 0001193125-21-361261 8-K/A as filed: Dec 17, 2021

Exhibit 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers of Independence Energy LLC

Opinion on the Financial Statements

We have audited the accompanying combined and consolidated balance sheets of Independence Energy LLC and subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related combined and consolidated statements of operations, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.

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 Public Company Accounting Oversight Board (United States) (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 and in accordance with auditing standards generally accepted in the United States of America. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

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.

/s/ Deloitte & Touche LLP

Houston, Texas

July 23, 2021

We have served as the Company’s auditor since 2021.

INDEPENDENCE ENERGY LLC

COMBINED AND CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)


	December 31, 2020			December 31, 2019
ASSETS
Current assets:
Cash and cash equivalents	$	36,861		$	19,894
Accounts receivable, net		111,821			103,300
Derivative assets – current		30,926			31,469
Drilling advances		38,892			4,770
Prepaid and other current assets		1,948			6,392

Total current assets		220,448			165,825
Property, plant and equipment:
Oil and natural gas properties at cost, successful efforts method
Proved		4,910,059			4,420,557
Unproved		288,459			326,331

Oil and natural gas properties at cost, successful efforts method		5,198,518			4,746,888
Field and other property and equipment, at cost		138,371			108,172

Total property, plant and equipment		5,336,889			4,855,060
Less: accumulated depreciation, depletion, amortization and impairment		(1,694,742	)		(1,081,521	)

Property, plant and equipment, net		3,642,147			3,773,539
Derivative assets – noncurrent		22,352			35,192
Other assets		22,422			22,964

Total assets	$	3,907,369		$	3,997,520

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	80,688		$	129,370
Accounts payable – affiliates		9,019			5,850
Derivative liabilities – current		26,392			61,727
Other current liabilities		4,572			3,939

Total current liabilities		120,671			200,886
Long-term debt		751,075			972,100
Derivative liabilities – noncurrent		23,958			13,858
Asset retirement obligations		106,403			80,423
Other liabilities		12,102			18,187

Total liabilities		1,014,209			1,285,454
Commitments and contingencies (Note 10)
Equity:
Members’ equity – Class A units, 1,220,421 and no units outstanding as of December 31, 2020 and 2019, respectively		2,716,892			1,881,733
Noncontrolling interests		176,268			830,333

Total equity		2,893,160			2,712,066

Total liabilities and equity	$	3,907,369		$	3,997,520

The accompanying notes to financial statements are an integral part of these combined and consolidated financial statements

INDEPENDENCE ENERGY LLC

COMBINED AND CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except unit and per unit amounts)


	Year Ended December 31,
	2020			2019			2018
Revenues:
Oil	$	491,780		$	785,750		$	839,867
Natural gas		149,317			173,386			173,769
Natural gas liquids		69,902			86,473			133,874
Midstream and other		43,222			41,631			51,650

Total revenues		754,221			1,087,240			1,199,160
Expenses:
Lease operating expense		202,180			255,106			246,224
Workover expense		6,385			9,789			7,972
Asset operating expense		39,023			40,364			36,171
Gathering, transportation and marketing		173,122			142,214			134,358
Production and other taxes		61,124			88,696			90,709
Depreciation, depletion and amortization		372,300			311,185			267,883
Impairment of oil and natural gas properties		247,215			—			—
Exploration expense		486			469			5,815
Midstream operating expense		9,472			9,968			15,918
General and administrative expense		16,542			2,357			14,365
(Gain) loss on sale of assets		—			(22	)		11,557

Total expenses		1,127,849			860,126			830,972

Income (loss) from operations		(373,628	)		227,114			368,188
Other income (expense):
Interest expense		(38,107	)		(53,577	)		(48,401	)
Other income (expense)		341			402			945
Gain (loss) on derivatives		195,284			(127,202	)		56,562

Total other income (expense)		157,518			(180,377	)		9,106

Income (loss) before taxes		(216,110	)		46,737			377,294
Income tax expense		(14	)		(28	)		(220	)

Net income (loss)		(216,124	)		46,709			377,074
Less: net (income) loss attributable to noncontrolling interests		97,475			(870	)		(98,168	)

Net income (loss) attributable to members	$	(118,649	)	$	45,839		$	278,906

Weighted-average Class A Units outstanding – basic and diluted		773,979			620,206			620,206
Net income (loss) per Class A Unit – basic and diluted	$	(153.30	)	$	73.91		$	449.70

The accompanying notes to financial statements are an integral part of these combined and consolidated financial statements

INDEPENDENCE ENERGY LLC

COMBINED AND CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(in thousands)


	Class A Units		Members’ Equity		Noncontrolling Interest		Total
Balance at January 1, 2018		—	$	1,230,606	$	532,909	$	1,763,515
Net income		—		278,906		98,168		377,074
Contributions		—		623,984		273,659		897,643
Distributions		—		(172,765)		(57,621)		(230,386)

Balance at December 31, 2018		—		1,960,730		847,114		2,807,844
Net income		—		45,839		870		46,709
Contributions		—		—		250		250
Distributions		—		(124,836)		(17,901)		(142,737)

Balance at December 31, 2019		—		1,881,733		830,333		2,712,066
Net loss		—		(118,649)		(97,475)		(216,124)
Contributions				4,704		—		4,704
Distributions		—		(61,421)		(1,146)		(62,567)
Issuance of Class A Units in exchange for the Contributed Entities		620,206		—		—		—
Reclassification of noncontrolling interests		—		(101,926)		101,926		—
Issuance of Class A Units in exchange for the acquisition of Titan Energy		379,794		455,081		—		455,081
December 2020 Exchange (see Note 2)		220,421		657,370		(657,370)		—

Balance at December 31, 2020		1,220,421	$	2,716,892	$	176,268	$	2,893,160

The accompanying notes to financial statements are an integral part of these combined and consolidated financial statements

INDEPENDENCE ENERGY LLC

COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Year Ended December 31,
	2020			2019			2018
Cash flows from operating activities:
Net income (loss)	$	(216,124	)	$	46,709		$	377,074
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		372,300			311,185			267,883
Impairment of oil and natural gas properties		247,215			—			—
(Gain) loss on sale of oil and natural gas properties		—			(22	)		11,557
(Gain) loss on derivatives		(195,284	)		127,202			(56,562	)
Net realized gain (loss) on settlement of derivatives		186,495			(22,743	)		(125,107	)
Equity-based compensation expense		(797	)		(2,721	)		8,005
Write-offs of other long-term assets		—			3,804			317
Debt issuance cost amortization		4,941			4,730			3,451
Other		(29	)		105			(117	)
Changes in operating assets and liabilities:
Accounts receivable		14,652			24,104			(39,935	)
Prepaid and other current assets		17,769			(1,133	)		(494	)
Other assets		117			45			(116	)
Accounts payable and accrued liabilities		(15,138	)		(5,514	)		42,348
Accounts payable – affiliates		657			27			(17,274	)
Other liabilities		(5,746	)		(263	)		(107	)

Net cash provided by operating activities		411,028			485,515			470,923
Cash flows from investing activities:
Development of oil and natural gas properties		(126,164	)		(338,646	)		(207,154	)
Acquisitions of oil and natural gas properties		—			—			(1,461,876	)
Proceeds from the sale of oil and natural gas properties		9,362			15,798			52,968
Purchases of restricted investment securities – HTM		(9,071	)		(5,412	)		(11,061	)
Maturities of restricted investment securities – HTM		9,052			5,414			2,672
Due from related party		(7,353	)		(4,868	)		(1,085	)
Other investing		(766	)		(444	)		(2,928	)

Net cash used in investing activities		(124,940	)		(328,158	)		(1,628,464	)
Cash flows from financing activities:
Repayments of capital lease obligations		(215	)		(207	)		(35	)
Long-term debt borrowings		275,850			553,300			969,600
Long-term debt repayments		(496,875	)		(564,900	)		(513,900	)
Debt issuance costs		(3,333	)		(1,619	)		(8,747	)
Member contributions		5,186			—			623,984
Noncontrolling interest contributions		—			250			273,659
Member distributions		(61,422	)		(124,837	)		(172,765	)
Non-controlling interest distributions		(1,145	)		(17,901	)		(57,621	)
Due to related party		9,865			2,720			20,890
Other financing		—			2			(7,258	)

Net cash provided by (used in) financing activities		(272,089	)		(153,192	)		1,127,807

Net change in cash, cash equivalents and restricted cash		13,999			4,165			(29,734	)
Cash, cash equivalents and restricted cash, beginning of period		27,421			23,256			52,990

Cash, cash equivalents, and restricted cash, end of period	$	41,420		$	27,421		$	23,256

The accompanying notes to financial statements are an integral part of these combined and consolidated financial statements

(Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.)

References to “we,” “us”, “our” and the “Company” mean the results of Independence Energy LLC.

NOTE 1 – ORGANIZATION AND BASIS OF PRESENTATION

Organization

Independence Energy LLC is an independent energy company formed in June 2020 by investment funds and other entities affiliated with KKR & Co. Inc. (“KKR”), a global investment firm. We seek to generate attractive risk-adjusted returns and cash flow for our members through the exploration, development, production and acquisition of crude oil, natural gas and natural gas liquids (“NGLs”). We maintain a diverse portfolio of proven energy assets, including operated, non-operated, royalty and mineral interests and related midstream infrastructure in key proven basins across the United States, including the Eagle Ford, DJ, Permian and Barnett Basins and the Rockies.

We have evaluated how we are organized and managed and have identified only one operating segment, which is the exploration and production of crude oil, natural gas and NGLs. We consider our gathering, processing and marketing functions as ancillary to our oil and gas producing activities. All of our operations and assets are located in the United States, and substantially all of our revenues are attributable to United States customers.

Basis of Presentation

Our combined and consolidated financial statements (the “financial statements”) include the accounts of the Company and its subsidiaries after the elimination of intercompany transactions and balances and are presented in accordance with U.S. general accepted accounting principles (“GAAP”). We have no elements of other comprehensive income for the periods presented.

In August 2020, through a series of transactions, we underwent a reorganization (the “Reorganization”) in connection with the Titan Acquisition (as defined in Note 3 – Acquisitions and Divestitures), carried out under the direction of our Managing Member whereby certain entities (the “Contributed Entities”) previously owned and under the common control of affiliates of KKR were contributed to us. The financial statements include the accounts of the Contributed Entities from the date of the Reorganization, which is the date the Company obtained a controlling financial interest in these entities, to December 31, 2020 on a consolidated basis. As required by GAAP, the contributions of the Contributed Entities in connection with the Reorganization were accounted for as a reorganization of entities under common control, in a manner similar to a pooling of interests, with all assets and liabilities transferred to us at their carrying amounts. Further, because the Reorganization resulted in a change in reporting entity, and in order to furnish comparative financial information prior to the Reorganization, the financial statements have been retrospectively recast to reflect the historical accounts of the Contributed Entities on a combined basis.

Independence Energy LLC is a holding company that conducts substantially all of its business through its consolidated subsidiaries, including Independence Energy Finance LLC, its wholly owned subsidiary. Independence Energy LLC has no operations, cash flows, or material assets and liabilities other than its investment in Independence Energy Finance LLC.

The financial statements include undivided interests in oil and natural gas properties. We account for our share of oil and natural gas properties by reporting our proportionate share of assets, liabilities, revenues, costs, and cash flows within the accompanying combined and consolidated balance sheets, statements of operations, and statements of cash flows.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make use of estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We use historical experience and various other assumptions and information that are believed to be reasonable under the circumstances in developing our estimates and judgments. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results may differ from these estimates. Our significant estimates include the fair value of acquired assets and liabilities, oil and natural gas reserves, impairment of proved and unproved oil and natural gas properties and valuation of derivative instruments.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash deposited in commercial bank accounts and highly liquid investments purchased with an original maturity of three months or less at the date of purchase. Cash and cash equivalents are maintained with major financial institutions in the U.S. Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, the financial stability of the financial institutions is regularly monitored, and we believe that we do not have exposure to any significant default risk.

Restricted Cash

Restricted cash consists of funds earmarked for a special purpose and therefore not available for immediate and general use. The majority of our restricted cash is comprised of cash that is contractually required to be restricted to pay for the future abandonment of certain wells in California. Restricted cash is included in other current assets and other assets on our balance sheets.

The following table provides a reconciliation of cash and restricted cash presented on our balance sheets to amounts shown in the statements of cash flows:


	As of December 31,
	2020		2019		2018
	(in thousands)
Cash and cash equivalents	$	36,861	$	19,894	$	20,813
Restricted cash – current		—		3,932		—
Restricted cash – noncurrent		4,559		3,595		2,443

Total cash, cash equivalents and restricted cash	$	41,420	$	27,421	$	23,256

Accounts Receivable

We routinely assess the recoverability of our accounts receivable, which primarily comprise amounts due from (i) purchasers of our oil, natural gas and NGL production and (ii) joint interest owners on properties that we operate. We monitor our exposure to credit risk primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness. Generally, our oil and natural gas receivables are collected within 45 to 60 days of production. Our joint interest billings are collected within the month after they are billed, and we have the ability to withhold future revenue distributions to recover any nonpayment of our joint interest billings.

As a result of adopting ASU 2016-13, we establish allowances for credit losses equal to the estimable portions of accounts receivable for which failure to collect is expected to occur primarily based on a historical loss rate analysis. We estimate uncollectible amounts based on the length of time that the accounts receivables have been outstanding, historical collection experience and current and future economic and market conditions. We consider forecasts of future economic conditions in the estimate of our expected credit losses, in particular whether there is an increase in the probability that our counterparties will be unable to pay their obligations when due, and adjust our allowance for expected credit losses, when necessary. Our allowances for expected credit losses and bad debt were immaterial as of December 31, 2020 and 2019, respectively. We did not incur credit loss expense or bad debt expense related to our accounts receivable during the years ended December 31, 2020, 2019, and 2018. We do not have any off-balance sheet credit exposure related to our customers.

Restricted investment securities

We hold U.S. Treasury securities, which are contractually required to be set aside to pay for the future abandonment of certain wells in California. Due to this restriction, we report these investment securities as noncurrent and include them within other assets on our combined and consolidated balance sheets.

We classify our investment in these debt securities at the acquisition date and re-evaluate the classification at each balance sheet date. We classify debt securities purchased with the positive intent and ability to hold until their maturity date as held-to-maturity investments (“HTM”) and carry these investments at amortized cost. Premiums and discounts on purchases are amortized over the remaining time to maturity of the security and the amortization is recorded as an adjustment to interest income. At December 31, 2020 and 2019, we had restricted investment securities – HTM with a carrying value of $8.5 million and $8.4 million, respectively.

Oil and Natural Gas Properties

Oil and natural gas producing activities are accounted for under the successful efforts method of accounting. Under this method, exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Capitalized costs attributed to the properties are charged as an operating expense through depreciation, depletion and amortization (“DD&A”). Dry hole costs associated with developing proved fields are capitalized. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs (“G&G”) and costs of certain nonproducing leasehold costs are expensed once evaluated and determined to be a dry hole. We incurred exploration expense of $0.5 million, $0.5 million, and $5.8 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Delay and surface rentals are charged to expense as incurred. The costs to acquire mineral interests in oil and natural gas properties and lease acquisition costs are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold costs are transferred to proved properties.

The capitalized costs of producing oil and natural gas properties are depleted on a field-by-field basis using the units-of-production method based on the ratio of current production to estimated total net proved oil, natural gas and NGL reserves. Proved developed reserves are used in computing depletion rates for drilling and development costs and total proved reserves are used for depletion rates of leasehold costs.

Upon the sale of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated DD&A are removed from the property accounts and any gain or loss is recognized.

Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. See discussion of Asset Retirement Obligations below for additional discussion.

During the years ended December 31, 2020, 2019 and 2018, we recognized depletion expense of $364.7 million, $300.9 million and $258.3 million, respectively.

Other Property, Plant, and Equipment

We have other property, plant, and equipment that consists principally of gathering and processing facilities, vehicles, computer hardware and software, office furniture and equipment, buildings and leasehold improvements. Other property, plant, and equipment is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the respective assets which range from three to thirty years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. The cost of maintenance and repairs are expensed in the period incurred. Expenditures that extend the life or improve existing property and equipment are capitalized.

Impairment

Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. When a triggering event is identified, we compare the carrying amount of our oil and natural gas properties to the estimated undiscounted cash flows our oil and natural gas properties will generate to determine if the carrying amount is recoverable. We perform this analysis on an investments pool basis. If the carrying amount exceeds the estimated undiscounted cash flows, we will write-down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, and discount rates commensurate with the risk associated with realizing the projected cash flows.

In March 2020, crude oil demand experienced significant declines due to the coronavirus disease 2019 (COVID-19) global pandemic and resulting governmental led shut-downs in economic activity. During the second quarter of 2020, as it became apparent that the pandemic would continue indefinitely with sustained significant decline in crude oil prices, we assessed our oil and natural gas properties for impairment and incurred impairment expense of $247.2 million during the year ended December 31, 2020. We did not incur any impairment expense during the years ended December 31, 2019 and 2018.

Drilling Advances

We pay advances for certain drilling and completion costs on our non-operated properties, as required by our joint operating agreements. At December 31, 2020 and 2019, we had $38.9 million and $4.8 million, respectively, of outstanding advances, reflected net of any related accrued capital expenditures, on our combined and consolidated balance sheets.

Other long-term assets

We acquired certain long-term joint interest receivables that are settled through the underlying oil and natural gas interests of certain joint interest owners. The outstanding balance of these long-term receivables was $1.3 million as of December 31, 2020 and 2019. We recognized write-offs of acquired long-term joint interest receivables totaling $3.8 million within operating expense in the combined and consolidated statement of operations for the year ended December 31, 2019.

Members’ Equity and Noncontrolling interest

We have two classes of equity in the form of Class A Units and Class B Units. Both Class A Units and Class B Units are considered common units, and distributions are made pro rata in accordance with each Unit’s respective ownership percentage. As of December 31, 2020, all outstanding Class A Units were held by two entities (i) an affiliate of KKR and (ii) an unrelated third-party. No Class B Units were issued or outstanding during the year.

We record noncontrolling interest associated with third party ownership interests in our combined and consolidated subsidiaries. Income or loss associated with these interests is classified as net income (loss) attributable to noncontrolling interest on our combined and consolidated statements of operations.

In December 2020, certain owners of noncontrolling equity interests in certain of our consolidated subsidiaries elected to exchange 100% of their interests in those individual consolidated subsidiaries for 220,421 of our Class A units (“December 2020 Exchange”). Since we already consolidate the results of these subsidiaries, this transaction was accounted for as a reclassification of $657.4 million from noncontrolling interest to members’ equity with no gain or loss recognized on the exchange.

In August 2020, in connection with the Reorganization, certain interests in our consolidated subsidiaries owned by a third-party investor were not contributed to the Company. These interests were reclassified from members’ equity to noncontrolling interest as of the date of the Reorganization and all income and loss attributable to these interests is recorded as net income (loss) attributable to noncontrolling interests for the period from the date of the Reorganization through the year-ended December 31, 2020.

The following table discloses the effects of changes in the Company’s ownership interest in its subsidiaries on equity associated with the August and December events mentioned above:


	Year Ended December 31,
	2020			2019		2018
	(in thousands)
Net income (loss) attributable to members	$	(118,649	)	$	45,839	$	278,906
Transfers (to) from noncontrolling interest
Decrease in members’ equity related to the Reorganization		(101,926	)		—		—
Increase in members’ equity related to the December 2020 Exchange		657,370			—		—

Net transfers (to) from the noncontrolling interest		555,444			—		—

Changes from net income (loss) attributable to members and transfers (to) from noncontrolling interest	$	436,795		$	45,839	$	278,906

Debt Issuance Costs

We capitalize costs incurred in connection with obtaining financing associated with our revolving credit facilities and amortize such costs as additional interest expense over the life of the underlying indebtedness. These costs include fees paid to financial institutions and legal fees and are included in other assets in our combined and consolidated balance sheets.

Revenue Recognition

Oil, Gas and NGL Revenues

We hold operated and non-operated interests in producing assets that function as follows:

Operated working interests: We are responsible for the day-to-day management and operation of the field as well as negotiations required for post-production transportation, gathering, processing, and marketing; we remit proceeds from sales of resulting hydrocarbons to third parties back to non-operators less costs as agreed in the applicable joint operating agreement.

Non-operated working interests: An operator of these assets is responsible for the day-to-day management and operation of the field as well as negotiations required for post-production transportation, gathering, processing, and marketing; the operator then remits proceeds from sales of resulting hydrocarbons to third parties back to non-operators less costs as agreed in the applicable joint operating agreement.

Royalty Interests: Ownership of a percentage of production or production revenues produced from leased acreage. The owner of this share of production does not bear any of the cost of exploration, drilling, producing, operating, or any other expense associated with drilling and producing an oil and gas well. Royalty interests may be burdened by some or all of the post-production costs related to gathering, processing, and marketing.

We sell oil production at the lease and collect an agreed-upon index price, net of pricing differentials.

Under our natural gas contracts, we deliver natural gas to a midstream processor at a contractually specified delivery point. The processor gathers and processes the natural gas and then markets and remits proceeds to us for the resulting sale of the residue gas and NGLs.

Our non-operated production is marketed by operators, after which the operators remit net proceeds from the sale of our share of production to us. Proceeds reflect post-production expenses such as gathering, processing and other expenses incurred in marketing of that production.

Performance Obligations

Under product sales contracts, each unit of product generally represents a separate performance obligation. We record revenue for our product sales contracts at the point-in-time control of a commodity is transferred to the customer. However, settlement statements from non-operated working interests may not be received for 30 to 60 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the customer and the net commodity price that will be received for the sale of these commodity products.

At the end of the reporting period, we did not have any unsatisfied performance obligations. Our contracts with customers typically include variable consideration based on monthly pricing tied to local indices and volumes delivered in the current month. The nature of our contracts with customers does not require us to constrain variable consideration for accounting purposes.

Revenue is recognized to the extent it is determined that it is probable that a significant reversal will not occur. We record the differences between our revenue estimates and the actual amounts received in the month that payment is received from the operator.

Incentive Compensation

Incentive compensation includes liability-classified share-based payments issued to employees and non-employees. Liability-classified awards are remeasured at fair value until settlement. For awards with service-based vesting conditions only, we recognize compensation cost using straight-line attribution. For awards that contain market or performance conditions we use accelerated attribution. Our policy is to recognize forfeitures as they occur. Certain of our consolidated subsidiaries have also issued incentive awards that are accounted for similar to cash bonus plans, whereby compensation cost is measured based on the present value of probable expected benefits to be paid and recognized over the period services are provided. Incentive awards similar to cash bonus plans may also have market-based or time-based vesting conditions and are presented as accounts payable and accrued liabilities on our combined and consolidated balance sheets.

Incentive compensation cost is presented as general and administrative expense on our combined and consolidated statements of operations. See Note 11 – Incentive Compensation for additional discussion.

Business Combinations

We recognize the identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values. Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value. These fair values are accounted for at the date of acquisition and included in our combined and consolidated balance sheets as of December 31, 2020 and 2019. The results of operations of an acquired business are included in our combined and consolidated statements of operations from the date of the acquisition.

Credit and Concentration Risk

We sell a significant amount of our oil, natural gas and NGL production to a limited number of purchasers. This concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our purchasers may be similarly affected by changes in economic, industry, or other conditions. If these counterparties were to fail to pay amounts due to us, our financial position and results of operations could be materially affected.

The below purchasers represented greater than 10% of our combined and consolidated revenues during the years ended December 31, 2020, 2019 and 2018:


	2020			2019			2018
SN EF Maverick, LLC		15.5	%		20.0	%		24.4	%
Eighty Eight Oil		11.7	%		*			*
Shell Trading US Company		10.4	%		*			*
Cokinos Energy Corporation		*			18.1	%		27.8	%
BP Products North America		*			13.1	%		14.5	%

*	Purchaser did not account for greater than 10% of revenue for the year

We believe that the loss of any of our purchasers would not result in a material adverse effect on our ability to market future oil and natural gas production.

Risks and Uncertainties

Our future financial condition, results of operations and cash flows are dependent on the demand and prices received for oil, natural gas and NGL production. Oil, natural gas and NGL prices historically have been volatile, and we expect such volatility to continue in the future. Prices for oil, natural gas and NGL are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil, natural gas and NGL, market uncertainty and a variety of additional factors beyond our control. These factors include the supply of oil, natural gas and NGL, the level of consumer demand, weather conditions, government regulations and taxes, the price and availability of alternative fuels and overall economic conditions. A decline in oil, natural gas or NGL prices may adversely affect our financial position, cash flows, and results of operations. Lower oil, natural gas or NGL prices also may reduce the amount of oil, natural gas and NGL that can be produced economically.

Oil, natural gas and NGL revenues are derived principally from uncollateralized sales to numerous companies in the oil and natural gas industry; therefore, our customers may be similarly affected by changes in economic and other conditions within the industry.

Risk Management

We periodically enter into derivative contracts to manage our exposure to commodity price and interest rate changes. These derivative contracts may take the form of forward contracts, futures contracts, swaps, swaptions, collars or options. We do not use derivative contracts for trading purposes and have not designated any derivative

instruments as hedging instruments for accounting purposes. As such, unrealized gains and losses from changes in the valuation of our unsettled derivative contracts, as well as realized gains and losses on the settlement of derivative contracts, are reported in gain (loss) on derivatives in our combined and consolidated statements of operations.

Such derivative instruments are initially recorded at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value at each reporting date. Derivatives are carried as assets when the fair value is positive or as liabilities when the fair value is negative and are classified as current and long term based on the delivery periods of the financial instruments. If the right of offset exists and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on our combined and consolidated balance sheets.

See Note 6 – Fair Value Measurements.

Contingencies

Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. In the preparation of our financial statements, management assesses the need for accounting recognition or disclosure of these contingencies, if any, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

When applicable, we will accrue an undiscounted liability for contingencies where the incurrence of a loss is 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 amount within the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when it is believed to be only reasonably possible or remote.

For contingencies where an unfavorable outcome is reasonably possible and the impact would be material, we disclose the nature of the contingency and, if feasible, an estimate of the possible loss or range of loss. Loss contingencies considered remote are generally not disclosed. See Note 10 – Commitments and Contingencies.

Income Taxes

We and our subsidiaries are organized as Delaware limited liability companies and Delaware limited partnerships and are treated as flow-through entities for U.S. federal income tax purposes. As a result, our net taxable income and any related tax credits are passed through to our members or partners, as applicable, and are included in their tax returns even though such net taxable income or tax credits may not have actually been distributed. Accordingly, we are not subject to any U.S. federal income taxes. We are subject to certain state income taxes, such as the Texas Margin Tax, in certain jurisdictions in which we operate, and any provisions for such taxes are included in income tax expense on our combined and consolidated statements of operations.

Asset Retirement Obligations

An ARO represents the legal obligation associated with the future abandonment of tangible assets, such as wells, service assets, pipelines, and other facilities. We record an ARO and capitalize the asset retirement cost in oil and natural gas properties in the period in which the ARO is incurred based upon the estimated fair value of the obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO liability is accreted to its future estimated value using an estimated credited-adjusted risk-free rate and the capitalized asset retirement cost is depleted on a unit-of-production basis. Both the accretion expense and the depletion expense are included in depreciation, depletion and amortization expense on our combined and consolidated statements of operations.

Measuring the future ARO requires management to make estimates, assumptions, and judgments inherent in the present value calculation including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset. If the ARO is settled for an amount other than the recorded amount, a gain or loss is recognized at settlement.

See Note 9– Asset Retirement Obligations.

Environmental Expenditures

In addition to ARO, management also reviews our estimates of the cleanup costs of various sites on an annual basis. When it is probable that obligations have been incurred, and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related ongoing site assessments. We do not discount any of these liabilities. Recoveries for environmental remediation costs from third parties, which are probable of realization, are separately recorded and are not offset against the related environmental liability. As of December 31, 2020 and 2019, we did not have any probable environmental costs.

Supplemental Cash Flow Disclosures

The following are our supplemental cash flow disclosures for the years ended December 31, 2020, 2019 and 2018 (in thousands):


	Year Ended December 31,
	2020		2019		2018
Supplemental cash flow disclosures:
Interest paid, net of amounts capitalized	$	33,902	$	49,397	$	43,605
Income taxes paid		14		28		30
Non-cash investing and financing activities:
Capital expenditures included in accounts payable and accrued liabilities		12,267		28,305		51,521
Titan Energy acquisition, net of cash acquired – see Note 3		454,599		—		—
Capital lease obligations		—		—		581
December 2020 Exchange		657,370		—		—

Recent Accounting Standards

In August 2018, the FASB issued ASU 2018-13, Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement. The objective of this update is to improve the effectiveness of fair value measurement disclosures. ASU 2018-13 is effective for annual periods beginning after December 15, 2019, and interim periods within those annual periods. This standard was adopted on January 1, 2020 and is reflected in our disclosures.

In June 2018, the FASB issued ASU 2018-07, Compensation-Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting, which expands the scope of Topic 718 to include all share-based payment transactions for acquiring goods and services from nonemployees. ASU 2018-07 is effective for annual periods beginning after December 15, 2019 for all entities other than public business entities, and early adoption is permitted. The adoption of this standard on January 1, 2020 did not have a material impact on our financial statements or related disclosures.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments, Credit Losses, which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. This standard is intended to provide more timely decision-useful information about the expected credit losses on financial instruments. In November 2018, the FASB issued ASU No. 2018-19, “Codification Improvements to Topic 326, Financial Instruments–Credit Losses,” which makes amendments to clarify the scope of the guidance, including the amendment clarifying that receivables arising from operating leases are not within the scope of Topic 326. Accounts receivable from sales of oil and natural gas and joint interest receivables are the primary financial assets that are within the scope of the new guidance. A loss-rate method is applied to these receivables to estimate credit losses. The adoption of this standard on January 1, 2020 did not have a material impact on our financial statements or related disclosures.

In February 2016, the FASB issued ASU 2016-02, Leases, which establishes comprehensive accounting and financial reporting requirements for leasing arrangements. This ASU requires lessees to recognize substantially all lease assets and lease liabilities on the balance sheets. Additional disclosures about an entity’s lease transactions will also be required. ASU 2016-02 defines a lease as “a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration.” In November 2019 and June 2020, the FASB issued ASU No. 2019-10 and ASU No. 2020-05, respectively, that grant entities in the “all other” category a deferral of the effective date for its leases standard. As a result, this guidance is effective for our 2022 annual financial statements; however, early adoption is permitted. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified retrospective approach. As an emerging growth company, we plan to adopt ASU 2016-02 effective January 1, 2022. We are substantially complete with the assessment of our existing accounting policies and documentation, and enhancement of our internal controls. Adoption of the standard will result in the recognition of additional lease assets and liabilities on our combined and consolidated balance sheet as well as additional disclosures. The adoption is not expected to have a material impact to our combined and consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09 Revenue from Contracts with Customers, which requires an entity to recognize revenue in a manner that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, the amendment provides five steps that an entity should apply when recognizing revenue. The amendment also specifies the accounting of some costs to obtain or fulfill a contract with a customer and expands the disclosure requirements around contracts with customers. An entity can either adopt this amendment retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the update recognized at the date of initial application. In August 2015, the FASB issued ASU 2015-14, which delays the effective date by one year, making the new standard effective for annual reporting periods beginning after December 15, 2018. In March 2016, ASU 2014-09 was amended by the provisions of ASU 2016-08, which clarifies principal versus agent considerations. In April 2016, ASU 2014-09 was amended by the provisions of ASU 2016-10, which clarifies two principles of Accounting Standards Codification Topic 606: identifying performance obligations and the licensing implementation guidance. We adopted ASU 2014-09 utilizing a modified retrospective approach effective January 1, 2019, and there was no material impact on our consolidated financial statements and related disclosures.

NOTE 3 – ACQUISITIONS AND DIVESTITURES

During the three years ended December 31, 2020, we completed the following acquisitions, each of which was accounted for using the acquisition method under GAAP, which requires the acquired assets and liabilities be recorded at fair value as of the acquisition date:

Titan Energy Acquisition

In August 2020, through a series of transactions, we consummated the acquisition of all of the outstanding membership interests in Liberty Energy LLC (and the oil and natural gas assets owned thereby) pursuant to the Contribution Agreement, dated as of July 19, 2020, by and among Independence Energy LLC, Liberty Energy Holdings, LLC (“Liberty Holdco”) and the other parties thereto, in consideration for the issuance of certain membership interests in Independence Energy LLC to an entity substantially owned by Liberty Holdco. Subsequent to the acquisition, we changed the name of Liberty Energy, LLC to Titan. Titan owns certain working interests in non-operated producing and non-producing oil and natural gas properties in the Permian, DJ, Eagle Ford, and Arkoma Basins, which includes a 50% interest in the DJ Basin Erie Hub Gathering System. The fair value of net assets acquired equaled the fair value of the consideration transferred of $455.1 million, and we recognized transaction related expenses of $8.7 million for the year ended December 31, 2020. We expect to complete the purchase price allocation during the second quarter of 2021.

Barnett Gas Acquisition

In May 2018, we acquired certain producing natural gas properties located in North Texas, certain related derivatives, other property and equipment and working capital items from Devon Energy Production Company, L.P. for $480.2 million.

Frio Atascosa Eagle Ford Oil Acquisition

In February 2018, we acquired certain producing and non-producing oil and gas properties located in the Eagle Ford area of South Texas (the “Frio Atascosa Eagle Ford Oil acquisition”) for total cash consideration of $728.2 million. From June 2018 through September 2018, we completed a series of unrelated bolt-on acquisitions adjacent to these properties for aggregate consideration of approximately $253.5 million. We incurred approximately $1.9 million of acquisition costs related to these acquisitions.

The following table summarizes, for each of the above acquisitions, the consideration transferred and the estimated fair value of identified assets acquired and liabilities assumed at the date of each respective acquisition:


	2020			2018
	Titan Energy			Barnett Gas			Frio Atascosa Eagle Ford Oil
	(in thousands)
Consideration transferred:
Cash	$	—		$	480,165		$	981,683
Membership interest		455,081			—			—

Total	$	455,081		$	480,165		$	981,683

Assets acquired and liabilities assumed:
Cash	$	482		$	—		$	—
Accounts receivable – oil and gas		21,788			952			—
Derivative assets – current		12,000			2,906			—
Prepaid and other current assets		49,079			—			—
Oil and natural gas properties:
Proved properties		375,014			498,098			933,729
Unproved properties		—			—			55,884
Other property, plant, and equipment		30,232			5,846			—
Equipment inventory		—			—			1,092
Derivative assets – noncurrent		114			5,624			—
Accounts payable and other liabilities		(6,185	)		(3,892	)		(1,832	)
Derivative liabilities – current		(4,550	)		(9,946	)		—
Derivative liabilities – noncurrent		(1,484	)		(2,474	)		—
Asset retirement obligations		(21,409	)		(16,949	)		(7,190	)

Fair value of net assets acquired	$	455,081		$	480,165		$	981,683

From the date of the Titan acquisition through December 31, 2020, revenues and net income associated with the operations acquired through the acquisition were $88.2 million and $16.7 million, respectively.

The following table summarizes the unaudited pro forma financial information of the Company for the year ended December 31, 2020 and 2019 as if the acquisition occurred on January 1, 2019:


	Year Ended December 31,
	2020			2019
	(in thousands)
Revenues	$	857,920		$	1,409,789
Net income (loss)	$	(519,524	)	$	49,359

The unaudited pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the acquisition been completed on January 1, 2019, nor is it necessarily indicative of future operating results of the combined entity.

Midland and Ector County Divestiture

In March 2020, we received the remaining $3.9 million from the deep rights sale, described further below, and recognized the reduction to our oil and gas properties for the full sale of $7.9 million.

In December 2019, we entered into a Term Assignment of Oil and Gas Lease conveying all of our interest in the Midland and Ector county leases between the top of the Mississippian formation down to the base of the Woodford formation, “deep rights”, for total bonus consideration of $7.9 million and a primary term of four years from the effective date, January 1, 2020. We received $4.0 million in December 2019 when the agreement was signed and the remainder was received in March 2020. As of December 31, 2019, the $4.0 million payment was included in accounts receivable – affiliates and deferred in accounts payable and accrued liabilities.

Eagle Ford Divestiture

In September 2019, we entered into a purchase, sale and exchange agreement with an unaffiliated third party, which encompassed the sale of certain producing properties and exchange of oil and gas leases in the Eagle Ford area of South Texas in exchange for cash consideration of $15.2 million and additional post-closing settlement consideration of $1.8 million, $1.2 million of which was received in 2020.

Mississippi Asset Divestiture

In December 2018, we sold all of our interests in the Mississippi assets we acquired in 2014 for which we received $15.0 million of proceeds and recognized $33.1 million of loss on sale of oil and natural gas properties in our combined and consolidated statements of operations.

Eagle Ford Non-operated Divestiture

In May 2018, we sold our interests in certain oil and natural gas properties for a total of $38.0 million cash and recognized $21.5 million of gain on sale of oil and natural gas properties in our combined and consolidated statements of operations.

NOTE 4 – PROPERTY, PLANT, AND EQUIPMENT

The following table summarizes our oil and natural gas properties as of December 31, 2020 and 2019:


	As of December 31,
	2020			2019
	(in thousands)
Proved oil and natural gas properties (successful efforts method)	$	4,910,059		$	4,420,557
Unproved oil and natural gas properties		288,459			326,331

Oil and natural gas properties, at cost		5,198,518			4,746,888
Less accumulated depreciation, depletion, amortization and impairment		(1,633,664	)		(1,058,551	)

Oil and natural gas properties, net	$	3,564,854		$	3,688,337

Other Property

The following table summarizes other property, plant and equipment as of December 31, 2020 and 2019:


	Estimated useful life		As of December 31,
	Estimated useful life		2020			2019
	(years)		(in thousands)
Gathering and pipeline system		30	$	108,777		$	78,545
Vehicles		3-5		7,273			7,093
Computers, furniture, and equipment		3-10		6,812			6,498
Buildings and improvements		5-30		6,797			6,805
Land				5,700			5,700
Field Inventory				3,012			3,531

Total field and other property and equipment, at cost				138,371			108,172

Less: accumulated depreciation, amortization and impairment				(61,078	)		(22,970	)

Total field and other property and equipment, at cost			$	77,293		$	85,202

Capitalized exploratory well costs

Capitalized exploratory well costs are included in unproved oil and natural gas properties. The following table reflects the net changes in capitalized exploratory well costs for the years ended December 31, 2020 and 2019:


	Year Ended December 31,
	2020		2019
	(in thousands)
Balance at beginning of period	$	—	$	297
Additions pending the determination of proved reserves		—		710
Reclassifications to proved properties		—		(1,007	)
Costs charged to expense		—		—

Balance at end of period	$	—	$	—

As of December 31, 2020, we did not have any capitalized exploratory well costs.

NOTE 5 – DERIVATIVES

In the normal course of business, we are exposed to certain risks including changes in the prices of oil, natural gas and NGLs which may impact the cash flows associated with the sale of our future oil and natural gas production. We enter into derivative contracts with lenders under our revolving credit facilities that consist of either a single derivative instrument or a combination of instruments to manage our exposure to these risks.

As of December 31, 2020, our commodity derivative instruments consisted of fixed price swaps which are described below:

Fixed Price Swaps: Under a swap contract, we will receive payment if the settlement price is less than the fixed price and would be required to make a payment to the counterparty if the settlement price is greater than the fixed price.

The following table details our net volume positions by commodity as of December 31, 2020:


Production Period	Volumes		Weighted Average Fixed Price			Fair Value
						(in thousands)
Crude oil swaps (Bbls):
WTI
2021		9,769,778	$	50.65		$	23,246
2022		7,368,902		47.19			4,082
2023		6,062,936		43.88			(10,628	)
Brent
2021		505,192		53.67			1,230
2022		481,800		56.57			3,146
2023		417,925		53.24			1,522
Natural gas swaps (MMBtu):
2021		69,539,483		2.75			7,528
2022		58,167,404		2.70			6,366
2023		46,912,477		2.48			761
NGL swaps (Bbls):
2021		3,717,002		16.61			(17,084	)
2022		1,516,120		16.12			(4,205	)
Crude oil basis swaps (Bbls):
2021		6,253,643		0.48			800
2022		3,534,661		0.74			(1,379	)
Natural gas basis swaps (MMBtu):
2021		26,606,125		(0.20	)		(2,720	)
2022		24,943,200		(0.17	)		(1,236	)
CMA Roll Hedges:
2021		4,434,097		(0.24	)		(1,495	)

Total						$	9,934

We have variable rate debt outstanding, which is subject to interest rate risk based on volatility in underlying interest rates. As of December 31, 2020, the fair value of our pay-fixed, receive-variable interest rate swaps was an unrealized loss of $7.0 million. Swap terms are as follows:


	Notional Amount		Floating Rate %		Weighted Average Interest Rate %
	(in thousands)
2021	$	535,000		1 Month LIBOR		2.94	%

We use derivative commodity instruments and enter into swap contracts which are governed by International Swaps and Derivatives Association master agreements. The following table shows the effects of master netting arrangements on the fair value of our derivative contracts at December 31, 2020 and 2019:


	Gross Fair Value			Effect of Counterparty Netting			Net Carrying Value
	(in thousands)
December 31, 2020
Assets:
Derivative assets – current	$	52,833		$	(21,907	)	$	30,926
Derivative assets – noncurrent		34,257			(11,905	)		22,352

Total assets	$	87,090		$	(33,812	)	$	53,278

Liabilities:
Derivative liabilities – current	$	(48,299	)	$	21,907		$	(26,392	)
Derivative liabilities – noncurrent		(35,863	)		11,905			(23,958	)

Total liabilities	$	(84,162	)	$	33,812		$	(50,350	)


	Gross Fair Value			Effect of Counterparty Netting			Net Carrying Value
	(in thousands)
December 31, 2019
Assets:
Derivative assets – current	$	37,950		$	(6,481	)	$	31,469
Derivative assets – noncurrent		38,951			(3,759	)		35,192

Total assets	$	76,901		$	(10,240	)	$	66,661

Liabilities:
Derivative liabilities – current	$	(68,208	)	$	6,481		$	(61,727	)
Derivative liabilities – noncurrent		(17,617	)		3,759			(13,858	)

Total liabilities	$	(85,825	)	$	10,240		$	(75,585	)

The amount of gain (loss) recognized in gain (loss) on derivatives in our combined and consolidated statements of operations was as follows for the years ended December 31, 2020, 2019 and 2018:


	Years ended December 31,
	2020			2019			2018
	(in thousands)
Derivatives not designated as hedging instruments:
Realized gain (loss) on oil positions	$	149,713		$	(44,265	)	$	(102,989	)
Realized gain (loss) on natural gas positions		32,638			4,245			(10,801	)
Realized gain (loss) on NGL positions		14,458			13,033			(22,048	)
Realized gain (loss) on interest hedges		(12,435	)		(2,189	)		(280	)

Total realized gain (loss)		184,374			(29,176	)		(136,118	)

Unrealized gain (loss) on commodity hedges		8,836			(94,766	)		195,279
Unrealized gain (loss) on interest hedges		2,074			(3,260	)		(2,599	)

Total unrealized gain (loss)		10,910			(98,026	)		192,680

Total gain (loss) on derivatives	$	195,284		$	(127,202	)	$	56,562

NOTE 6 – FAIR VALUE MEASUREMENTS

GAAP 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 (exit price). Generally, the determination of fair value requires the use of significant judgment and different approaches and models under varying circumstances. Under a market-based approach, we consider prices of similar assets, consult with brokers and experts, or employ other valuation techniques. Under an income-based approach, we generally estimate future cash flows and then discount them at a risk-adjusted rate. We classify the inputs used to measure the fair value of our financial assets and liabilities into the following hierarchy:

Level 1: Quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2: Quoted market prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets and liabilities in markets that are not active or other than quoted prices that are observable, either directly or indirectly, and can be corroborated by observable market data.

Level 3: Unobservable inputs that reflect management’s best estimates and assumptions of what market participants would use in measuring the fair value of an asset or liability.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of significance for a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities within the fair value hierarchy levels.

Recurring Fair Value Measurements

The following table presents the location and fair value of our derivative assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2020 and 2019, by level within the fair value hierarchy:


	Fair Value Measurement Using
	Level 1		Level 2			Level 3		Total
	(in thousands)
December 31, 2020
Financial assets:
Derivative assets	$	—	$	87,090		$	—	$	87,090
Financial liabilities:
Derivative liabilities	$	—	$	(84,162	)	$	—	$	(84,162	)
December 31, 2019
Financial assets:
Derivative assets	$	—	$	76,901		$	—	$	76,901
Financial liabilities:
Derivative liabilities	$	—	$	(85,825	)	$	—	$	(85,825	)

See Note 5– Derivatives.

Non-Recurring Fair Value Measurements

As stated in Note 2, in 2020, oil and natural gas properties were written down to their fair value resulting in an impairment expense of $247.2 million. The fair value was determined using a discounted cash flow model based on the expected present value of the future net cash flows from our oil and natural gas reserves. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include estimates of future prices, production costs, development expenditures, anticipated production, appropriate risk-adjusted discount rates, and other relevant data.

Our other non-recurring fair value measurements include the purchase price allocations for the fair value of assets and liabilities acquired through acquisitions of oil and natural gas properties. The fair value of these assets and liabilities is calculated using a discounted-cash flow approach using Level 3 inputs and is not remeasured in periods after initial recognition. See Note 3 – Acquisitions and Divestitures and Note 9– Asset Retirement Obligations.

Other Fair Value Measurements

The carrying value of cash, accounts receivable, accounts payable and accrued liabilities approximate their fair values due to the short-term maturities of these instruments. Our long-term debt obligations under our revolving credit facilities also approximate fair value since the associated variable rates of interest are market based.

NOTE 7– ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Accounts payable and accrued liabilities consisted of the following as of December 31, 2020 and 2019:


	As of December 31,
	2020		2019
	(in thousands)
Accounts payable and accrued liabilities:
Accounts payable	$	15,019	$	45,009
Accrued lease operating expense		20,126		27,172
Accrued asset operating expense		3,591		1,489
Accrued capital expenditure		11,793		28,305
Accrued general and administrative		9,549		1,895
Accrued transportation expense		8,399		13,759
Accrued deficiency fees		5,050		—
Other		7,161		11,741

Total accounts payable and accrued liabilities	$	80,688	$	129,370

NOTE 8 – DEBT

Overview

Certain of our subsidiaries have entered into revolving credit facilities with syndicates of lenders that expire between 2022 and 2024 (the “revolving credit facilities”). Our borrowings under these facilities are secured by a first priority lien on substantially all of the assets held by each subsidiary. Borrowings under each facility are generally used for the development and acquisition of oil and natural gas properties, working capital, and general corporate purposes, and such borrowings are limited in use by the subsidiary whose assets collateralize the debt. The amounts we may borrow under each of our revolving credit facilities is limited by a borrowing base, which is based on the oil and natural gas properties, proved reserves, total indebtedness, and other factors and is consistent with customary lending criteria. Borrowing bases are typically re-determined semi-annually, with provisions for additional redeterminations occurring after material acquisitions or dispositions, or more frequently at the request of our lenders.

Interest

Interest on borrowings is calculated using the London Interbank Offering Rate (“LIBOR”), plus an applicable margin. The applicable margin ranges from 2.00% to 4.00% for LIBOR loans, depending on the percentage of the total borrowing base utilization level. In addition to interest, we pay various fees, including a commitment fee per annum on the unutilized commitment, which is included within interest expense on our combined and consolidated statements of operations. The range of weighted average interest rate on loan amounts outstanding as of December 31, 2020 was 2.85% to 3.89%.

Covenants

Our revolving credit facilities contains certain covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity, commodity swap agreements, liens and other transactions without the adherence to certain financial covenants or the prior consent of our lenders. We are subject to (i) maximum leverage ratio and (ii) current ratio financial covenants calculated as of the last day of each fiscal quarter. Our facilities also contains representations, warranties, indemnifications and affirmative and negative covenants, including events of default relating to nonpayment of principal, interest or fees, inaccuracy of representations or warranties in any material respect when made or when deemed made, violation of covenants, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default occurs under our credit facilities and we are unable to cure such default, the lenders will be able to accelerate maturity and exercise other rights and remedies. There is no cross collateralization between our revolving credit facilities.

Letters of Credit

From time to time, we may request the issuance of letters of credit for our own account. Letters of credit accrue interest at a rate equal to the margin associated with LIBOR borrowings. At December 31, 2020 and 2019, we had letters of credit outstanding of $17.8 million and $18.6 million, respectively, which reduce the amount available to borrow under each of our revolving credit facilities. We had $751.1 million and $972.1 million in long-term debt outstanding as of December 31, 2020 and 2019, respectively.

The following table summarizes our revolving credit facilities as of December 31, 2020:


	As of December 31, 2020
	Debt Outstanding		Letters of Credit Issued		Borrowing Base		Maturity
	(in thousands)
Revolving Credit Facilities:
Independence Upstream Holdings LLC	$	32,500	$	—	$	100,000		6/7/2022
Independence Minerals Holdings LLC		15,000		—		37,000		10/25/2024
KNR Resource Investors LP		5,565		250		12,000		6/7/2022
Renee Acquisition LLC		101,310		5,667		145,000		1/31/2023
Newark Acquisition I LP		135,400		6,280		190,000		5/31/2023
Bridge Energy Holdings LLC		35,800		5,574		50,000		7/21/2022
Venado EF LP		156,500		—		160,000		3/10/2022
VOG Palo Verde LP		269,000		—		320,000		2/28/2023

Total long-term debt	$	751,075

The following table summarizes the five year maturities of our revolving credit facilities:


	As of December 31, 2020
	(in thousands)
2021	$	—
2022		230,365
2023		505,710
2024		15,000
2025		—

	$	751,075

NOTE 9 – ASSET RETIREMENT OBLIGATIONS

Our ARO liabilities are based on our net ownership in wells and facilities and management’s estimate of the costs to abandon and remediate those wells and facilities together with management’s estimate of the future timing of the costs to be incurred. The following table summarizes activity related to our ARO liabilities for the years ended December 31, 2020, 2019 and 2018:


	Year Ended December 31,
	2020			2019			2018
	(in thousands)
Balance at beginning of period	$	83,141		$	78,348		$	60,419
Additions		21,860			1,034			25,651
Retirements		(881	)		(1,008	)		(629	)
Accretion expense		5,694			4,767			4,619
Change in estimates		(198	)		—			—
Sale		—			—			(11,712	)

Balance at end of period		109,616			83,141			78,348
Less: current portion		(3,213	)		(2,718	)		(2,525	)

Balance at end of period, noncurrent portion	$	106,403		$	80,423		$	75,823

NOTE 10 – COMMITMENTS AND CONTINGENCIES

From time to time, we may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of business. We are currently unaware of any proceedings that, in the opinion of management, will individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows.

We are subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. We believe we are currently in compliance with all applicable federal, state and local regulations. Accordingly, no liability or loss associated with environmental remediation was recognized as of December 31, 2020 except for the following:

We were engaged with the Environmental Protection Agency (EPA) for alleged violations of the Clean Water Act between 2016 and 2018. We have settled these allegations with the EPA and have recorded $1.4 million as a liability and expense at December 31, 2020.

Oil Gathering Agreement

voting or other control rights, but do provide us with an incentive distribution right if other unit classes receive distributions equal to contributed capital plus targeted rates of return. We account for the Series D units through the fair value option available under ASC 825, Financial Instruments. As of December 31, 2020 and 2019, we have concluded the fair value of our investment is not material, based on the nature of the Series D units and overall risk inherent in receiving future cash flows given the stage of development of the entity and required return hurdles.

Carbon Dioxide Purchase Agreement

We assumed one take-or-pay carbon dioxide purchase agreement as part of a prior acquisition. The agreement includes a minimum volume commitment to purchase carbon dioxide at a price stipulated in the contract. The agreement provides carbon dioxide for use in our enhanced recovery projects in certain of our properties. The daily minimum volume commitments are 175 MMcf/per day through May 2021 and 140 MMcf/per day from June 2021 to May 2026, with the commitment effectively ending in May 2026. We expect to purchase more carbon dioxide through the end of the agreement in 2026 than our minimum volume commitments, and, in accordance with the agreement, if we do not meet our minimum volume commitments for a year (or years), we can make up the volumes in future years through 2029 as long as we pay for our minimum volumes each year. As of December 31, 2020 and 2019, we have met required minimum volumes.

Oil and Natural Gas Transportation and Gathering Agreements

We have entered into certain oil and natural gas transportation and gathering agreements with various pipeline carriers. Under these agreements, we are obligated to ship minimum daily quantities or pay for any deficiencies at a specified rate. We are also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity that we utilize. If we do not utilize the capacity, we can release it to others, thus reducing our potential liability. We recognized $14.5 million, $1.9 million, and $1.2 million of transportation expense in our combined and consolidated statements of operations related to minimum volume deficiencies for the years ended December 31, 2020, 2019 and 2018, respectively.

The following table summarizes our future commitments related to these oil and natural gas transportation and gathering agreements as of December 31, 2020:


	As of December 31, 2020
	(in thousands)
2021	$	93,901
2022		89,568
2023		66,883
2024		54,183
2025		51,032
Thereafter		90,972

Total minimum future commitments	$	446,539

NOTE 11 – INCENTIVE COMPENSATION

Overview

Certain of our subsidiaries have entered into award agreements to grant profits interests and other incentive awards to employees and non-employees. These liability-classified awards may contain certain service-, performance-, and market-based vesting conditions, which are further discussed below.

Liability-classified share-based payments

Certain of our subsidiaries issue profits interests that are classified as equity-based liability awards. These awards contain different vesting conditions ranging from market-based conditions that vest upon the achievement of certain return thresholds to time-based service requirements ranging from three to four years. Each of these profits interests are liability-classified due to their repurchase features. Compensation cost for these awards is presented within general and administrative expense with a corresponding credit to other long-term liabilities. The fair value of these awards is remeasured as of the end of each reporting period until settlement.

Incentive compensation cost for liability-classified share-based payments was ($0.8) million, ($2.5) million, and $6.6 million for the years ended December 31, 2020, 2019 and 2018, respectively. Unrecognized compensation cost related to non-vested awards was $1.6 million, $5.0 million, and $10.7 million for the years ended December 31, 2020, 2019 and 2018, respectively, and is expected to be recognized over a weighted-average period of two years. There were no cash settlements of liability-classified share-based payments during the year ended December 31, 2020.

Our time-based awards were measured at fair value using a Monte Carlo simulation as of December 31, 2020. We estimated the expected term of each award considering various exit scenarios. Expected volatility was based on the average of historical and implied volatility of a set of comparable companies, adjusted for size and leverage. The risk-free rate used was based on the yields of U.S. Treasury instruments with comparable terms.

The fair value of the units vested during the year using the fair value measurement as of December 31, 2020 was $7.7 million. As of December 31, 2020, the accounting impact of the market-based awards was determined to be immaterial to the financial statements.

Incentive awards other than share based payments

Certain of our subsidiaries have also issued incentive awards that require continuous service in order to receive distributions, but do not represent an equity interest. As these incentive awards are similar to a cash bonus plan, compensation cost is measured based on the present value of expected benefits that are probable of being paid and recognized over the period services are provided. Compensation cost is remeasured at each reporting period based on expected future benefits and is attributed over the performance period on a straight-line basis. We did not recognize any compensation cost for this type of incentive award for the year ended December 31, 2020.

NOTE 12 – RELATED PARTY TRANSACTIONS

KKR

Pursuant to our management agreement with the Manager (the “Management Agreement”), the Manager has agreed to provide us with management services and other assistance, including with respect to strategic planning, identifying acquisitions, screening and referring potential investments, recommending strategies for exit from investments, executing our authorized investments and providing such other assistance as we may require, including, without limitation, preparing valuations and reports necessary or appropriate for our compliance with our Amended & Restated Limited Liability Company Agreement, dated August 18, 2020 (the “LLC Agreement”). As consideration for its services, KKR has the right to a quarterly management fee to the extent future capital is raised from third parties, to be calculated in accordance with the terms of our LLC Agreement. Our Management Agreement has a perpetual term unless terminated by the mutual consent of us and the Manager or by the removal of the Manager as the Managing Member under our LLC Agreement.

FDL

Certain of our consolidated subsidiaries have entered into an Oil and Natural Gas Property Operating and Services Agreement (the “Agreement”) with FDL. FDL’s management owns less than 0.15% of our Class A

Units and holds noncontrolling interests in certain of our consolidated subsidiaries. Pursuant to the Agreement, FDL was engaged to manage the day-to-day operations of the business activities of our consolidated subsidiaries, including allocating to us and other interest holders the production and sale of oil, natural gas and natural gas liquids, collection and disbursement of revenues, operating expenses and general and administrative expenses in the respective oil and natural gas properties, and the payment of all capital costs associated with the ongoing operations of the oil and natural gas assets. As part of the engagement, FDL will then allocate the revenues, operating expenses, general and administrative expenses and cash collected to us and others as appropriate. We settle balances due to or due from FDL on a monthly basis.

As of December 31, 2020 and 2019, we had a net related party payable due to FDL totaling $7.5 million and $5.0 million, respectively, included within accounts payable – affiliates on our combined and consolidated balance sheets. During the years ended December 31, 2020, 2019 and 2018, we recorded $15.1 million, $18.9 million, and $15.2 million, respectively, as asset operating expenses for direct expenses processed by FDL.

RPM

A KKR entity has entered into a Master Management Services Agreement (the “MSA”) with a subsidiary of RPM Energy Management Partnership L.P. (“RPM”) to act as the manager of certain mineral and non-operated assets controlled by the Contributed Entities. Pursuant to the MSA and under management of KKR affiliates, RPM manages the day-to-day operations of the business activities of certain of our oil and natural gas properties. We reimburse RPM for all reasonable out-of-pocket expenses incurred for fulfilling its obligations under the MSA (“Allocable Overhead Costs”). The Allocable Overhead Costs are charged to us on an actual basis without mark-up or subsidy. As such, the Allocable Overhead Costs approximate reasonable market rates and are representative of the expenses that we would have incurred. We settle balances due to or due from RPM on a monthly basis.

As of December 31, 2020 and 2019 we had a payable due to RPM of $1.7 million and $0.5 million, respectively, included within other current liabilities on our combined and consolidated balance sheets.

NOTE 13 – EARNINGS PER UNIT

We have two classes of equity in the form of Class A Units and Class B Units. Both Class A Units and Class B Units are considered common units, and distributions are made pro rata in accordance with each Unit’s respective ownership percentage. As such, we apply the two-class method for purposes of calculating earnings per unit (“EPU”). Net income (loss) attributable to members is allocated to Class A Units and Class B Units in proportion to the pro rata ownership of each class after giving effect to distributions declared during the period, if any. There were no Class B Units issued or outstanding during the periods presented.

As described in Note 1 – Organization and Basis of Presentation, our financial statements have been retrospectively recast to reflect the historical accounts of the Contributed Entities on a combined basis due to the Reorganization. The denominator for our computation of net income (loss) per unit for periods prior to the Reorganization is calculated based on the number of Class A Units received by our parent as a result of the Reorganization.

The following table sets for the computation of basic and diluted net income (loss) per unit:


	Year Ended December 31,
	2020			2019			2018
	(in thousands, except unit and per unit amounts)
Numerator:
Net income (loss)	$	(216,124	)	$	46,709		$	377,074
Less: net (income) loss attributable to noncontrolling interests		97,475			(870	)		(98,168	)

Net income (loss) attributable to members	$	(118,649	)	$	45,839		$	278,906

Denominator:
Weighted-average Class A Units outstanding – basic and diluted		773,979			620,206			620,206
Net income (loss) per unit:
Class A Units – basic and diluted	$	(153.30	)	$	73.91		$	449.70

NOTE 14 – SUBSEQUENT EVENTS

Subsequent events have been evaluated through the date of issuance of these financial statements, and there have been no events subsequent to December 31, 2020, other than those items disclosed below, that would require additional adjustments to our disclosure in our financial statements.

Acquisition of DJ Minerals Asset

On March 5, 2021, we acquired a portfolio of oil & gas mineral assets from an unrelated third-party operator for a total value of $63.9 million. The purchase was funded using cash on hand and borrowings under our Independence Minerals Holdings LLC credit facility.

April 2021 Exchange

On April 1, 2021, certain co-investors exchanged 100% of their interests in our Barnett natural gas assets for 9,508 Class A Units, representing 0.77% of our consolidated ownership. Since we already consolidate the results of these assets, this transaction will be accounted for as an equity transaction and reflected as a reclassification from noncontrolling interests to members’ equity with no gain or loss recognized on the exchange.

$500.0 million Senior Notes Issuance

On May 6, 2021, Independence Energy Finance, LLC, our wholly owned subsidiary, issued $500.0 million aggregate principal amount of 7.250% Senior Notes due 2026 (the “notes”). The notes bear interest at an annual rate of 7.250%, which is payable on May 1 and November 1 of each year, and mature on May 1, 2026.

The notes will be our senior unsecured obligations and the notes and the guarantees will rank equally in right of payment with the borrowings under our New Credit Agreement (as defined later within this note) and all of our other future senior indebtedness and senior to any of our future subordinated indebtedness. The notes will be guaranteed on a senior unsecured basis by each of our existing and future subsidiaries that will guarantee our New Credit Agreement and certain other capital markets indebtedness. The notes and the guarantees will be effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our New Credit Agreement) to the extent of the value of the collateral securing such indebtedness, and

structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the notes.

We may, at our option, redeem all or a portion of the notes at any time on or after May 1, 2023 at certain redemption prices. We may also redeem up to 40% of the aggregate principal amount of the notes before May 1, 2023 with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.250% of the principal amount of the notes being redeemed, plus accrued and unpaid interest, if any, to, but excluding the redemption date. In addition, prior to May 1, 2023, we may redeem some or all of the notes at a price equal to 100% of the principal amount thereof, plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but excluding the redemption date.

If we sell certain of our assets or experience certain kinds of changes of control accompanied by a ratings decline, holders of the notes may require us to repurchase their notes. The notes will not be listed on any securities exchange, and currently there is no public market for the notes.

New Credit Agreement

Borrowings under the New Credit Agreement bear interest at either a U.S. dollar alternative base rate (based on the prime rate, the federal funds effective rate or an adjusted LIBOR), plus an applicable margin or LIBOR, plus an applicable margin, at the election of the borrowers. The applicable margin varies based upon our borrowing base utilization then in effect. The fee payable for the unused revolving commitments is 0.50% per year.

The borrowing base is subject to semi-annual scheduled redeterminations on November 1, 2021 and thereafter on or about April 1st and October 1st of each year, as well as (i) elective borrowing base interim redeterminations at our request not more than twice during any consecutive 12-month period or the required lenders not more than once during any consecutive 12-month period and (ii) elective borrowing base interim redeterminations at our request following any acquisition or acquisitions of oil and gas properties with a purchase price in the aggregate of at least 5.0% of the then effective borrowing base. The borrowing base will be automatically reduced upon (i) the issuance of certain permitted junior lien debt and other permitted additional debt, (ii) the sale or other disposition of borrowing base properties if the aggregate PV-9 of such properties sold or disposed of is in excess of 5.0% of the borrowing base then in effect and (iii) early termination or set-off (a) of swap agreements the administrative agent relied on in determining the borrowing base or (b) of swap agreements if the value of such swap agreements so terminated is in excess of 5.0% of the borrowing base then in effect.

The obligations under the New Credit Agreement remain secured by first priority liens on substantially all of the Company’s and the guarantors’ tangible and intangible assets, including without limitation, oil and natural gas properties and associated assets and equity interests owned by the Company and the guarantors. In connection with each redetermination of the borrowing base, the Company must maintain mortgages on at least 85% of the PV-9 of the oil and gas properties that constitute borrowing base properties. The Company’s domestic direct and indirect subsidiaries are required to be guarantors under the New Credit Agreement, subject to certain exceptions.

each fiscal quarter. The New Credit Agreement also contains representations, warranties, indemnifications and affirmative and negative covenants, including events of default relating to nonpayment of principal, interest or fees, inaccuracy of representations or warranties in any material respect when made or when deemed made, violation of covenants, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default occurs and we are unable to cure such default, the lenders will be able to accelerate maturity and exercise other rights and remedies.

Noncontrolling Interest Carve-out

In connection with the above refinancing transactions, certain of our consolidated subsidiaries redeemed the noncontrolling equity interests held in such subsidiaries by a third-party investor in exchange for the third-party investor’s proportionate share of the underlying oil and natural gas interests held by our consolidated subsidiaries. Additionally, the third-party investor contributed cash of approximately $35.4 million to repay their proportional share of the underlying debt outstanding under our prior revolving credit facilities and other liabilities. The percentage ownership of these certain consolidated subsidiaries owned by the third-party investor ranges from 2.21% to 7.38%.

Repayment of Prior Revolving Credit Facilities

The combined proceeds from the notes issuance, New Credit Agreement and Noncontrolling Interest Carve-Out were used to fully repay all amounts outstanding under our prior revolving credit facilities, which were then terminated upon the repayment of the remaining principal and accrued interest.

Arkoma Basin Divestiture

On May 18, 2021 we executed a purchase and sale agreement with an unaffiliated third-party which encompassed the sale of certain producing properties and oil and gas leases in the Arkoma Basin in exchange for cash consideration, net of closing adjustments, of $22.1 million, and recognized a $9.4 million of gain on sale of assets in our combined and consolidated statement of operations.

Distributions

In March 2021, we paid a distribution of $9.4 million for the three months ended December 31, 2020 to holders of our Class A Units.

In June 2021, we paid a distribution of $13.5 million for the three months ended March 31, 2021 to holders of our Class A Units.

Transaction Agreement

On June 7, 2021, we entered into a transaction agreement with Contango Oil & Gas Company (“Contango”) and certain other parties thereto, providing for the combination of Contango’s business with our business under a new publicly-traded holding company (“New PubCo”). The New PubCo will be structured as an “Up-C” with all of the assets and operations of each of us and Contango indirectly held by an operating subsidiary of New PubCo (such operating subsidiary “OpCo”). Contango shareholders will own New PubCo Class A Common Stock, which has both voting and economic rights with respect to New PubCo. Our equityholders will own economic, non-voting limited liability company interests in OpCo (“OpCo Units”) and corresponding New PubCo Class B Common Stock, which has voting (but no economic) rights with respect to New PubCo. New PubCo will be a holding company, the sole material assets of which will consist of OpCo Units. New PubCo will be the sole managing member of OpCo, will be responsible for all operational, management and administrative decisions relating to OpCo’s business and will consolidate the financial results of OpCo and its subsidiaries, including the

subsidiaries of Independence and Contango. The transaction will be consummated through a series of steps and closing is conditioned upon approval and adoption of the transaction agreement by Contango’s stockholders, expiration of the waiting period under the Hart-Scott-Rodino Act and other customary conditions.

Commodity Derivative Settlement

In June 2021, we settled certain of our outstanding derivative oil commodity contracts for $198.7 million, using borrowings of $160.0 million from our New Credit Agreement described below and cash on hand. Subsequent to the settlement, we entered into new commodity derivative contracts at prevailing market prices.

Derivative Contracts

The following table details our net volume positions by commodity as of June 30, 2021:


Production Period	Volumes		Weighted Average Fixed Price
Crude oil swaps (Bbls):
WTI
2021		4,701,323	$	51.79
2022		7,568,649		61.90
2023		6,130,506		58.71
2024		1,092,000		53.68
Brent
2021		252,973		53.68
2022		500,050		56.36
2023		527,425		52.52
Natural gas swaps (MMBtu):
2021		34,118,935		2.76
2022		58,959,088		2.70
2023		47,512,319		2.48
NGL swaps (Bbls):
2021		1,980,333		17.83
2022		2,242,125		17.02
Crude oil basis swaps (Bbls):
2021		3,147,390		0.49
2022		5,457,176		(0.15	)
Natural gas basis swaps (MMBtu):
2021		14,682,110		(0.20	)
2022		26,061,463		(0.17	)
CMA Roll Hedges:
2021		2,165,868		(0.24	)

NOTE 15 – SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (UNAUDITED)

Geographic Area of Operation

All of the oil and natural gas properties in which we have working interests and mineral and royalty interests are located within the continental U.S., with the majority concentrated in Texas, Wyoming and Colorado. Therefore, the following disclosures about our costs incurred and proved reserves are presented on a combined and consolidated basis.

Oil and Natural Gas Reserve Information

Subsequent to the issuance of the Company’s 2020 financial statements, we determined that certain of our reserve estimates contained reserves associated with uneconomic wells and did not include overhead or plugging and abandonment costs. As a result, we revised our December 31, 2020 and 2019 reserve balances. We believe the change is immaterial to the reserve totals as it represents a 4,070 MBoe (1%) and 7,665 MBoe (2%) decrease from the originally reported total MBoe December 31, 2020 and 2019 reserve balances. The following table presents our net proved reserves, on a revised basis, for the years ended December 31, 2020, 2019 and for the year ended December 31, 2018 and the changes in net proved oil, natural gas and NGL reserves during such years:


	Year Ended December 31, 2020
	Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)			Total (MBoe)
Net proved reserves at beginning of period		211,533			1,161,239			61,126			466,199
Revisions of previous estimates (1)		(57,708	)		(478,153	)		(20,279	)		(157,680	)
Extensions, discoveries, and other additions		4,088			21,479			603			8,271
Sales of reserves in place		—			—			—			—
Purchases of reserves in place		22,409			196,840			18,952			74,168
Production		(13,132	)		(78,541	)		(5,078	)		(31,300	)

Net proved reserves at end of period		167,190			822,864			55,324			359,658


	Year Ended December 31, 2019
	Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)			Total (MBoe)
Net proved reserves at beginning of period		202,805			1,189,962			75,780			476,913
Revisions of previous estimates		10,477			20,552			(11,321	)		2,581
Extensions, discoveries, and other additions		12,003			24,472			1,855			17,936
Sales of reserves in place		—			—			—			—
Purchases of reserves in place		—			—			—			—
Production		(13,752	)		(73,747	)		(5,188	)		(31,231	)

Net proved reserves at end of period		211,533			1,161,239			61,126			466,199


	Year Ended December 31, 2018
	Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)			Total (MBoe)
Net proved reserves at beginning of period		129,887			286,619			43,747			221,405
Revisions of previous estimates (2)		(15,332	)		(44,977	)		(8,902	)		(31,730	)
Extensions, discoveries, and other additions		3,288			5,561			512			4,727
Sales of reserves in place		(1,401	)		(39,913	)		(242	)		(8,296	)
Purchases of reserves in place		99,573			1,041,027			45,551			318,628
Production		(13,210	)		(58,355	)		(4,886	)		(27,821	)

Net proved reserves at end of period		202,805			1,189,962			75,780			476,913

(1)

Revisions of previous estimates include 92.0 MBoe downward revisions of our PUD reserves. The revisions are primarily due to declining commodity prices which decreased the quantity of reserves recoverable from our proved locations, and also resulted in the removal of certain PUD locations that were uneconomic at year end prices.

(2)	Revisions of previous estimates primarily related to the impact of certain of our operators’ bankruptcies on our oil and gas properties, and the removal of certain PUD locations related to those operators.

The following table sets forth our net proved oil, natural gas and NGL reserves, on a revised basis, as of the years ended December 31, 2020 and 2019, and as of the years ended December 31, 2018 and 2017:


Proved Developed Reserves	Oil (MBbls)		Natural Gas (MMcf)		Natural Gas Liquids (MBbls)		Total (MBoe)
December 31, 2020		92,024		748,496		44,307		261,079
December 31, 2019		103,728		870,491		48,997		297,808
December 31, 2018		113,917		933,774		60,275		329,820
December 31, 2017		79,618		196,258		26,919		139,248

Proved Undeveloped Reserves	Oil (MBbls)		Natural Gas (MMcf)		Natural Gas Liquids (MBbls)		Total (MBoe)
December 31, 2020		75,166		74,368		11,017		98,579
December 31, 2019		107,805		290,748		12,129		168,391
December 31, 2018		88,888		256,188		15,505		147,093
December 31, 2017		50,269		90,361		16,828		82,157

During the year ended December 31, 2020, we added 8,271 MBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin and in various mineral interests. Approximately 57% of the reserve additions for the year ended December 31, 2020 were crude oil and NGLs. Purchases in place of 74,168 MBoe were primarily related to the Permian and DJ Basins.

During the year ended December 31, 2019, we added 17,936 MBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian and Eagle Ford Basins. Approximately 77% of the reserve additions for the year ended December 31, 2019 were crude oil and NGLs.

During the year ended December 31, 2018, we added 318,628 MBoe of reserves through acquisitions in the Eagle Ford Shale and Barnett Shale. Approximately 54% of the acquired reserves for the year ended December 31, 2018 were natural gas, while 31% were crude oil.

Capitalized Costs Relating to Oil and Gas Producing Activities

The following table summarizes the capitalized costs relating to our crude oil and natural gas producing activities as of December 31, 2020 and 2019:


	As of December 31,
	2020			2019
	(in thousands)
Proved oil and natural gas properties (successful efforts method)	$	4,910,059		$	4,420,557
Unproved oil and natural gas properties		288,459			326,331
Oil and natural gas properties, at cost		5,198,518			4,746,888
Less accumulated depreciation, depletion and amortization		(1,666,620	)		(1,058,551	)

Net capitalized costs	$	3,531,898		$	3,688,337

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities.

Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include additions to exploratory wells, including those in progress, and exploration expenses. Development costs include additions to production facilities and equipment and additions to development wells, including those in progress.

The following table summarizes costs incurred related to our oil and gas activities years ended December 31, 2020, 2019 and 2018:


	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Acquisition costs:
Proved	$	355,010	$	795	$	1,426,838
Unproved		680		7,264		59,212
Exploration costs		—		710		397
Development		83,013		318,157		208,655

Total costs incurred	$	438,703	$	326,926	$	1,695,102

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information has been developed utilizing procedures prescribed by ASC 932 – Extractive Industries – Oil and Gas and based on crude oil, NGL and natural gas reserves and production volumes estimated by our engineering staff. The estimates were based on a 12-month average for commodity prices for the year ended December 31, 2017. The following information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating our performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of our current value.

The future cash flows presented below are based on sales prices and cost rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil, NGL and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible reserves as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

Subsequent to the issuance of the Company’s 2020 financial statements, we determined that certain of our reserve estimates contained reserves associated with uneconomic wells and did not include overhead or plugging and abandonment costs. As a result, we revised our December 31, 2020 and 2019 discounted future net cash flows. We believe the change is immaterial to the discounted future net cash flows totals as it represents a $3.4 million (less than 1%) decrease and a $1.6 million (less than 1%) increase from the originally reported December 31, 2020 and 2019 discounted future net cash flows totals. The following tables show the reserves on a revised basis.

The following table sets forth the standardized measure of discounted future net cash flows from projected production of our oil and gas reserves, on a revised basis, for the years ended December 31, 2020, 2019 and for the year ended December 31, 2018:


	Year Ended December 31,
	2020			2019			2018
	(in thousands)
Future cash inflows	$	8,232,932		$	15,745,942		$	18,281,840
Future production costs		(4,280,563	)		(6,766,410	)		(7,747,910	)
Future development costs(1)		(1,353,957	)		(2,323,420	)		(2,099,593	)
Future income taxes		(30,155	)		(63,136	)		(73,387	)

Future net cash flows		2,568,257			6,592,976			8,360,950
Annual discount of 10% for estimated timing		(1,240,397	)		(3,482,128	)		(4,153,603	)

Standardized measure of discounted future net cash flows	$	1,327,860		$	3,110,848		$	4,207,347

(1)	Future development costs include future abandonment and salvage costs.

Changes in standardized measure of discounted future net cash flows

The following table sets forth the changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2020, 2019 and 2018:


	Year Ended December 31,
	2020			2019			2018
	(in thousands)
Balance at beginning of period	$	3,110,848		$	4,207,347		$	1,394,865
Net change in prices and production costs		(1,184,939	)		(821,874	)		747,150
Net change in future development costs		160,465			(59,359	)		(1,568	)
Sales and transfers of oil and natural gas produced, net of production expenses		(290,053	)		(568,665	)		(720,524	)
Extensions, discoveries, additions and improved recovery, net of related costs		31,688			182,697			61,131
Purchases of reserves in place		176,480			—			2,583,348
Sales of reserves in place		—			—			(42,045	)
Revisions of previous quantity estimates		(887,395	)		(226,561	)		191,689
Previously estimated development costs incurred		32,873			15,676			27,420
Net change in taxes		19,350			(19	)		(22,825	)
Accretion of discount		283,954			424,278			138,904
Changes in timing and other		(125,411	)		(42,672	)		(150,198	)

Balance at end of period	$	1,327,860		$	3,110,848		$	4,207,347

Exhibit 99.2

INDEPENDENCE ENERGY LLC

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except unit data)


	September 30, 2021			December 31, 2020
ASSETS
Current assets:
Cash and cash equivalents	$	63,541		$	36,861
Accounts receivable, net		172,446			111,821
Accounts receivable - affiliates		5,423			—
Derivative assets - current		—			30,926
Drilling advances		6,212			38,892
Prepaid and other current assets		7,683			1,948

Total current assets		255,305			220,448
Property, plant and equipment:
Oil and natural gas properties at cost, successful efforts method
Proved		4,876,998			4,910,059
Unproved		312,784			288,459

Oil and natural gas properties at cost, successful efforts method		5,189,782			5,198,518
Field and other property and equipment, at cost		135,383			138,371

Total property, plant and equipment		5,325,165			5,336,889
Less: accumulated depreciation, depletion, amortization and impairment		(1,863,981	)		(1,694,742	)

Property, plant and equipment, net		3,461,184			3,642,147
Derivative assets - noncurrent		—			22,352
Other assets		21,339			22,422

Total assets	$	3,737,828		$	3,907,369

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	160,265		$	80,688
Accounts payable - affiliates		3,942			9,019
Derivative liabilities - current		345,553			26,392
Other current liabilities		3,726			4,572

Total current liabilities		513,486			120,671
Long-term debt		765,531			751,075
Derivative liabilities - noncurrent		145,601			23,958
Asset retirement obligations		106,489			106,403
Other liabilities		27,798			12,102

Total liabilities		1,558,905			1,014,209
Commitments and contingencies (See Note 9)
Equity:
Members’ equity - Class A units, 1,229,929 and 1,220,421 units outstanding as of September 30, 2021 and December 31, 2020, respectively		2,165,256			2,716,892
Noncontrolling interests		13,667			176,268

Total equity		2,178,923			2,893,160

Total liabilities and equity	$	3,737,828		$	3,907,369

The accompanying notes are an integral part of these combined and consolidated financial statements

INDEPENDENCE ENERGY LLC

COMBINED AND CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands, except unit and per unit data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
Revenues:
Oil	$	222,074		$	125,692		$	627,817		$	341,808
Natural gas		86,779			34,725			230,271			87,113
Natural gas liquids		47,322			18,473			121,613			42,415
Midstream and other		9,553			11,722			34,017			30,631

Total revenues		365,728			190,612			1,013,718			501,967
Expenses:
Lease operating expense		58,338			49,142			175,966			144,140
Workover expense		2,932			1,199			7,823			4,270
Asset operating expense		10,810			8,354			24,306			27,265
Gathering, transportation and marketing		44,634			51,507			136,056			118,798
Production and other taxes		28,090			14,343			80,276			40,761
Depreciation, depletion and amortization		73,025			83,439			233,122			231,270
Impairment of oil and natural gas properties		—			—			—			233,957
Exploration expense		754			248			833			468
Midstream operating expense		2,518			1,812			8,848			7,620
General and administrative expense		11,024			7,237			33,775			10,198
(Gain) loss on sale of assets		(1	)		—			(9,418	)		—

Total expenses		232,124			217,281			691,587			818,747

Income (loss) from operations		133,604			(26,669	)		322,131			(316,780	)
Other income (expense):
Interest expense		(12,984	)		(8,386	)		(37,810	)		(29,555	)
Other income (expense)		(48	)		982			(54	)		126
Gain (loss) on derivatives		(282,222	)		(66,932	)		(885,032	)		299,780

Total other income (expense)		(295,254	)		(74,336	)		(922,896	)		270,351

Income (loss) before taxes		(161,650	)		(101,005	)		(600,765	)		(46,429	)
Income tax expense		393			—			407			13

Net income (loss)		(162,043	)		(101,005	)		(601,172	)		(46,442	)
Less: net (income) loss attributable to noncontrolling interests		1,476			31,015			15,368			61,008

Net income (loss) attributable to members	$	(160,567	)	$	(69,990	)	$	(585,804	)	$	14,566

Weighted-average Class A Units outstanding - basic and diluted		1,229,929			801,847			1,226,795			681,195
Net income (loss) per Class A Unit - basic and diluted	$	(130.55	)	$	(87.29	)	$	(477.51	)	$	21.38

The accompanying notes are an integral part of these combined and consolidated financial statements

INDEPENDENCE ENERGY LLC

COMBINED AND CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

(in thousands, except unit data)


	Class A Units		Members’ equity			Noncontrolling interest			Total
Balance at June 30, 2020		—	$	1,954,365		$	800,031		$	2,754,396
Net income (loss)		—		(69,990	)		(31,015	)		(101,005	)
Distributions		—		—			(409	)		(409	)
Reclassification of noncontrolling interests		—		(101,926	)		101,926			—
Issuance of Class A Units in exchange for the acquisition of Titan Energy		379,794		452,866			—			452,866
Issuance of Class A Units in exchange for the Contributed Entities		620,206		—			—			—

Balance at September 30, 2020		1,000,000	$	2,235,315		$	870,533		$	3,105,848

Balance at January 1, 2020		—	$	1,881,733		$	830,333		$	2,712,066
Net income (loss)		—		14,566			(61,008	)		(46,442	)
Contributions		—		740			—			740
Distributions				(12,664	)		(718	)		(13,382	)
Reclassification of noncontrolling interests		—		(101,926	)		101,926			—
Issuance of Class A Units in exchange for the acquisition of Titan Energy		379,794		452,866			—			452,866
Issuance of Class A Units in exchange for Contributed Entities		620,206		—			—			—

Balance at September 30, 2020		1,000,000	$	2,235,315		$	870,533		$	3,105,848

Balance at June 30, 2021		1,229,929	$	2,337,661		$	16,768		$	2,354,429
Net income (loss)		—		(160,567	)		(1,476	)		(162,043	)
Distributions		—		(11,838	)		(268	)		(12,106	)
Equity based compensation		—		—			57			57
Repurchase of noncontrolling interest		—		—			(1,414	)		(1,414	)

Balance at September 30, 2021		1,229,929	$	2,165,256		$	13,667		$	2,178,923

Balance at January 1, 2021		1,220,421	$	2,716,892		$	176,268		$	2,893,160
Net income (loss)		—		(585,804	)		(15,368	)		(601,172	)
Contributions		—		7,164			35,461			42,625
Distributions		—		(35,047	)		(546	)		(35,593	)
Noncontrolling Interest Carve-out (see Note 3)		—		—			(121,872	)		(121,872	)
Equity based compensation		—		—			3,189			3,189
April 2021 exchange (see Note 11)		9,508		62,051			(62,051	)		—
Repurchase of noncontrolling interest		—		—			(1,414	)		(1,414	)

Balance at September 30, 2021		1,229,929	$	2,165,256		$	13,667		$	2,178,923

The accompanying notes are an integral part of these combined and consolidated financial statements

INDEPENDENCE ENERGY LLC

COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)


	Nine Months Ended September 30,
	2021			2020
Cash flows from operating activities:
Net income (loss)	$	(601,172	)	$	(46,442	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		233,122			231,270
Impairment of oil and natural gas properties		—			233,957
(Gain) loss on sale of oil and natural gas properties		(9,418	)		—
(Gain) loss on derivatives		885,032			(299,780	)
Net realized gain (loss) on settlement of derivatives		(389,142	)		154,753
Noncash equity-based compensation expense		14,054			831
Amortization of debt issuance costs and discount		6,809			3,402
Write-off of debt issuance costs		2,541			—
Other		715			(12	)
Changes in operating assets and liabilities:
Accounts receivable		(67,588	)		32,685
Accounts receivable - affiliates		(9,363	)		(901	)
Prepaid and other current assets		27,898			(1,242	)
Accounts payable and accrued liabilities		60,112			(9,070	)
Accounts payable - affiliates		(4,720	)		2,243
Other		(248	)		(4,260	)

Net cash provided by operating activities		148,632			297,434
Cash flows from investing activities:
Development of oil and natural gas properties		(83,697	)		(110,049	)
Acquisitions of oil and natural gas properties		(65,391	)		—
Proceeds from the sale of oil and natural gas properties		22,053			9,272
Purchases of restricted investment securities - HTM		(6,746	)		(5,906	)
Maturities of restricted investment securities - HTM		8,121			5,887
Other investing		(1,116	)		(594	)

Net cash used in investing activities		(126,776	)		(101,390	)
Cash flows from financing activities:
Repayments of capital lease obligations		(247	)		(167	)
Proceeds from issuance of the notes, net of discount		486,029			—
New Credit Agreement borrowings		386,062			—
New Credit Agreement repayments		(108,000	)		—
Payment of debt issuance costs		(6,284	)		(1,651	)
Prior Credit Agreement borrowings		53,900			198,350
Prior Credit Agreement repayments		(804,975	)		(359,575	)
Member contributions		—			740
Noncontrolling interest contributions		35,461			—
Repurchase of noncontrolling interest		(1,414	)		—
Member distributions		(35,047	)		(12,664	)
Noncontrolling interest distributions		(546	)		(718	)

Net cash provided by (used in) financing activities		4,939			(175,685	)

Net change in cash, cash equivalents and restricted cash		26,795			20,359
Cash, cash equivalents and restricted cash, beginning of period		41,420			27,421

Cash, cash equivalents and restricted cash, end of period	$	68,215		$	47,780

The accompanying notes are an integral part of these combined and consolidated financial statements

(Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data are stated in thousands of dollars.)

References to “we,” “us,” “our” and the “Company” mean the results of Independence Energy LLC.

NOTE 1 – ORGANIZATION AND BASIS OF PRESENTATION

Organization

Independence Energy LLC is a diversified, well-capitalized U.S. independent energy company with a portfolio of assets in key proven basins across the lower 48 states. We seek to deliver attractive risk-adjusted investment returns and predictable cash flows across cycles by employing our differentiated approach to investing in the oil and natural gas industry. Our approach includes a cash flow-based investment mandate with a focus on operated working interests and is complemented by non-operated working interests, mineral and royalty interests and midstream infrastructure, as well as an active risk management strategy. We pursue our strategy through the production, development and acquisition of crude oil, natural gas and natural gas liquids (“NGLs”) reserves. We maintain a diverse portfolio of assets in key proven basins across the United States, including the Eagle Ford, DJ, Permian, Barnett and the Rockies.

Contango Transaction

On June 7, 2021, we, along with Contango Oil & Gas Company (“Contango”) and several entities formed by an affiliate of KKR including IE PubCo Inc. (“New PubCo”), IE OpCo LLC (“OpCo”), and certain entities formed by New PubCo (“IE C Merger Sub Inc.” and “IE L Merger Sub Inc.”) entered into an all-stock transaction (the “Contango Transaction”) providing for the combination of Contango’s business with our business under New PubCo. In connection with closing, New Pubco will be renamed Crescent Energy Company. The new company will be structured as an “Up-C”, with all of the assets and operations of each of Independence and Contango indirectly held by OpCo, an operating subsidiary of New PubCo. As a result of these transactions, (a) former owners of Independence will own approximately 75% of OpCo, 100% of the total outstanding New PubCo Class B Common Stock and approximately 75% of the total outstanding New PubCo Class A Common Stock and New PubCo Class B Common Stock taken together, (b) former stockholders of Contango will own New PubCo Class A Common Stock representing approximately 25% of the outstanding New PubCo Class A Common Stock and New PubCo Class B Common Stock, taken together and (c) New PubCo will own approximately 25% of the OpCo Units. Additionally, Independence Energy Aggregator LP, an affiliate of certain former owners of Independence, will be the sole holder of New PubCo’s non-economic Series I preferred stock, $0.0001 par value per share, which will entitle the holder thereof to appoint the Board of Directors of New PubCo and to certain other approval rights. The approval of Contango stockholders must be obtained before these transactions can be completed. Approval of the Contango Transaction requires the affirmative vote of holders of a majority of the outstanding shares of Contango common stock entitled to vote on the matter. If approved, the Contango Transaction is expected to close in December 2021. On July 23, 2021 New PubCo filed a joint proxy/prospectus (the “Proxy”) with the U.S. Securities and Exchange Commission (the “SEC”) that further describes the Contango Transaction.

Basis of Presentation

Our unaudited combined and consolidated financial statements (the “financial statements”) include the accounts of the Company and its subsidiaries after the elimination of intercompany transactions and balances, are presented in accordance with U.S. general accepted accounting principles (“GAAP”) and reflect all adjustments, consisting of normal recurring adjustments, that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective interim periods. We have no elements of other comprehensive income for the periods presented. Our annual report for the year ended December 31, 2020 includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this quarterly report. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the audited combined and consolidated financial statements included in the annual report.

In August 2020, through a series of transactions, we underwent a reorganization (the “Reorganization”) in connection with the Titan Acquisition (as defined in Note 3 – Acquisitions and Divestitures), carried out under the direction of our Managing Member (as defined in our Amended & Restated Limited Liability Company Agreement, dated August 18, 2020 (the “LLC Agreement”)), whereby certain entities (the “Contributed Entities”) previously owned and under the common control of affiliates of Kohlberg Kravis Roberts & Co. L.P. (“KKR”) were contributed to us. The financial statements include the accounts of the Contributed Entities from the date of the Reorganization, which is the date the Company obtained a controlling financial interest in the Contributed Entities, on a consolidated basis. As required by GAAP, the contributions of the Contributed Entities in connection with the Reorganization were accounted for as a reorganization of entities under common control, in a manner similar to a pooling of interests, with all assets and liabilities transferred to us at their carrying amounts. Further, because the Reorganization resulted in a change in reporting entity, and in order to furnish comparative financial information prior to the Reorganization, the financial statements have been retrospectively recast to reflect the historical accounts of the Contributed Entities on a combined basis.

Independence Energy LLC is a holding company that conducts substantially all of its business through its consolidated subsidiaries, including Independence Energy Finance LLC, its wholly owned subsidiary. Independence Energy LLC has no material operations, cash flows or material assets and liabilities other than its investment in Independence Energy Finance LLC.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Restricted Cash

Restricted cash consists of funds earmarked for a special purpose and therefore not available for immediate and general use. The majority of our restricted cash comprises cash that is contractually required to be restricted to pay for the future abandonment of certain wells in California.

The following table provides a reconciliation of cash and cash equivalents and restricted cash as reflected within our unaudited consolidated balance sheets to amounts shown in the unaudited combined and consolidated statements of cash flows:


	As of September 30,

	2021		2020

	(in thousands)
Cash and cash equivalents	$	63,541	$	43,499
Restricted cash – noncurrent		4,674		4,281

Total cash, cash equivalents and restricted cash	$	68,215	$	47,780

Supplemental Cash Flow Disclosures


	Nine Months Ended September 30,

	2021		2020

	(in thousands)
Supplemental cash flow disclosures:
Interest paid, net of amounts capitalized	$	13,608	$	27,066
Income taxes paid		407		13
Noncash investing and financing activities:
Capital expenditures included in accounts payable and accrued liabilities		36,568		4,380
Noncash purchase price adjustment - see Note 3		7,164		452,383
Capitalized noncash equity-based compensation - see Note 3		3,373		—

Recent Accounting Standards

In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases, which establishes comprehensive accounting and financial reporting requirements for leasing arrangements. ASU 2016-02 requires lessees to recognize substantially all lease assets and lease liabilities on the balance sheet. Additional disclosures about an entity’s lease transactions will also be required. ASU 2016-02 defines a lease as “a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration.” In November 2019 and June 2020, the FASB issued ASU No. 2019-10 and ASU No. 2020-05, respectively, that grant entities in the “all other” category a deferral of the effective date for its leases standard. As a result, this guidance is effective for our 2022 annual financial statements; however, early adoption is permitted. Under the expected modified retrospective approach of adoption prior periods are not required to be restated. As an emerging growth company, we plan to adopt ASU 2016-02 effective January 1, 2022. We are substantially complete with the assessment of our existing accounting policies and documentation and with the enhancement of our internal controls. Adoption of ASU 2016-02 will result in the recognition of additional lease assets and liabilities on our consolidated balance sheet as well as additional disclosures. The adoption is not expected to have a material impact to our combined and consolidated financial statements.

NOTE 3 – ACQUISITIONS AND DIVESTITURES

Central Basin Platform Acquisition

In September 2021, we entered into a purchase and sale agreement with an unrelated third-party to acquire certain operated producing oil and natural gas properties predominantly located in the Central Basin Platform in Texas and New Mexico, with additional properties in the southwestern Permian and Powder River Basins, for a purchase price of $71.3 million, subject to customary closing adjustments. We closed the transaction in December 2021 using borrowings under our New Credit Agreement (as defined below) and cash on hand.

Arkoma Basin Divestiture

In May 2021, we executed a purchase and sale agreement with an unaffiliated third-party that encompassed the sale of certain producing properties and oil and natural gas leases in the Arkoma Basin in exchange for cash consideration, net of closing adjustments, of $22.1 million. We recognized a $9.4 million gain on sale of assets in our unaudited combined and consolidated statements of operations for the nine months ended September 30, 2021, as a result of the transaction.

Noncontrolling Interest Carve-out

In May 2021, certain of our consolidated subsidiaries redeemed the noncontrolling equity interests held in such subsidiaries by a third-party investor in exchange for the third-party investor’s proportionate share of the underlying oil and natural gas interests held by our consolidated subsidiaries (the “Noncontrolling Interest Carve-out”). Additionally, the third-party investor contributed cash of approximately $35.5 million to repay its proportionate share of the underlying debt outstanding under our Prior Credit Agreements (as defined below) and other liabilities.

The percentage ownership of these certain consolidated subsidiaries owned by the third-party investor ranged from 2.21% to 7.38%.

DJ Basin Acquisition

In March 2021, we acquired a portfolio of oil and natural gas mineral assets located in the DJ Basin from an unrelated third-party operator for total consideration of $60.8 million (the “DJ Basin Acquisition”). The DJ Basin Acquisition was funded using cash on hand and borrowings under our Prior Credit Agreements. We accounted for the DJ Basin Acquisition as an asset acquisition and the purchase price was allocated 35.6% to proved oil and natural gas properties and 64.4% to unproved oil and natural gas properties. In conjunction with the DJ Basin Acquisition, we issued equity-based compensation, a portion of which is classified within permanent equity as noncontrolling interest and the remainder of which is classified as other liabilities, to certain parties of the transaction. See Note 10—Equity Based Payment Arrangements for additional information.

Titan Acquisition

In August 2020, through a series of transactions, we consummated the acquisition of all of the outstanding membership interests in Liberty Energy, LLC (and the oil and natural gas assets owned thereby) (the “Titan Acquisition”) pursuant to the Contribution Agreement, dated as of July 19, 2020, by and among Independence Energy LLC, Liberty Energy Holdings, LLC (“Liberty Holdco”) and the other parties thereto, in consideration for the issuance of certain membership interests in Independence Energy LLC to an entity substantially owned by Liberty Holdco. Subsequent to the acquisition, we changed the name of Liberty Energy, LLC to Titan Energy Holdings, LLC (“Titan”). Titan owns certain working interests in non-operated producing and non-producing oil and natural gas properties in the Permian, DJ, Eagle Ford and Arkoma Basins, which includes a 50% interest in the DJ Basin Erie Hub Gathering System. During the nine months ended September 30, 2020, we transferred $452.9 million of membership interests in the form of 0.4 million Class A units. Subsequent to September 30, 2020, due to post-closing adjustments that increased the purchase price, we issued an additional $9.1 million in membership interest, $7.2 million of which was recorded during the nine months ended September 30, 2021.

The following table summarizes the finalized purchase price as of September 30, 2021, including consideration transferred and the estimated fair value of identified assets acquired and liabilities assumed:


	Titan
	(in thousands)
Consideration transferred:
Membership interest	$	461,983

Total	$	461,983

Assets acquired and liabilities assumed:
Cash	$	482
Accounts receivable, net		29,044
Derivative assets – current		12,000
Prepaid and other current assets		49,079
Oil and natural gas properties:
Proved properties		375,014
Other property, plant and equipment		30,232
Derivative assets – noncurrent		114
Accounts payable and other liabilities		(6,539	)
Derivative liabilities – current		(4,550	)
Derivative liabilities – noncurrent		(1,484	)
Asset retirement obligations		(21,409	)

Fair value of net assets acquired	$	461,983

NOTE 4 – DERIVATIVES

In the normal course of business, we are exposed to certain risks including changes in the prices of oil, natural gas and NGLs, which may impact the cash flows associated with the sale of our future oil and natural gas production. We enter into derivative contracts primarily with counterparties who are also lenders under our revolving credit facility that consist of either a single derivative instrument or a combination of instruments to manage our exposure to these risks.

As of September 30, 2021, our commodity derivative instruments consisted of fixed price swaps. Under a swap contract, we will receive payment if the settlement price is less than the fixed price and would be required to make a payment to the counterparty if the settlement price is greater than the fixed price.

In June 2021, we settled certain of our outstanding derivative oil contracts associated with calendar years 2022 and 2023 for $198.7 million, using borrowings of $160.0 million from our New Credit Agreement (as defined below) and cash on hand. Subsequent to the settlements, we entered into new commodity derivative contracts at prevailing market prices.

The following table details our open commodity derivative contracts as of September 30, 2021:


Production Period	Volumes		Weighted Average Fixed Price			Fair Value
	(in thousands)					(in thousands)
Crude oil swaps (Bbls):
WTI
2021		2,348	$	52.60		$	(51,393	)
2022		8,582		62.22			(68,386	)
2023		7,097		58.79			(37,312	)
2024		2,380		56.01			(10,777	)
Brent
2021		126		53.69			(2,999	)
2022		500		56.36			(8,333	)
2023		527		52.52			(8,124	)
2024		91		60.95			(379	)
Natural gas swaps (MMBtu):
2021		18,760		2.87			(56,848	)
2022		68,712		2.77			(114,347	)
2023		50,878		2.51			(49,946	)
2024		454		2.94			(105	)
NGL swaps (Bbls):
2021		969		17.80			(27,333	)
2022		2,242		17.02			(45,949	)
Crude oil basis swaps (Bbls):
2021		1,550		0.47			(418	)
2022		5,843		(0.11	)		(3,325	)
Natural gas basis swaps (MMBtu):
2021		7,189		(0.20	)		(709	)
2022		26,061		(0.17	)		(3,637	)
CMA roll swaps (Bbls):
2021		1,071		(0.24	)		(834	)

Total						$	(491,154	)

We use derivative commodity instruments and enter into swap contracts that are governed by International Swaps and Derivatives Association master agreements. The following table shows the effects of master netting arrangements on the fair value of our derivative contracts as of September 30, 2021 and December 31, 2020:


	Gross Fair Value			Effect of Counterparty Netting			Net Carrying Value

	(in thousands)
September 30, 2021
Assets:
Derivative assets – current	$	1,837		$	(1,837	)	$	—
Derivative assets – noncurrent		178			(178	)		—

Total assets	$	2,015		$	(2,015	)	$	—

Liabilities:
Derivative liabilities – current	$	(347,390	)	$	1,837		$	(345,553	)
Derivative liabilities – noncurrent		(145,779	)		178			(145,601	)

Total liabilities	$	(493,169	)	$	2,015		$	(491,154	)

December 31, 2020
Assets:
Derivative assets – current	$	52,833		$	(21,907	)	$	30,926
Derivative assets – noncurrent		34,257			(11,905	)		22,352

Total assets	$	87,090		$	(33,812	)	$	53,278

Liabilities:
Derivative liabilities – current	$	(48,299	)	$	21,907		$	(26,392	)
Derivative liabilities – noncurrent		(35,863	)		11,905			(23,958	)

Total liabilities	$	(84,162	)	$	33,812		$	(50,350	)

See Note 5 – Fair Value Measurements for more information.

The amount of gain (loss) recognized in gain (loss) on derivatives in our unaudited combined and consolidated statements of operations was as follows for the three and nine months ended September 30, 2021 and 2020:


	Three Months Ended September 30,						Nine Months Ended September 30,

	2021			2020			2021			2020

	(in thousands)						(in thousands)
Derivatives not designated as hedging instruments:
Realized gain (loss) on oil positions	$	(49,121	)	$	32,249		$	(115,107	)	$	118,879
Realized loss on early settlement of certain oil positions		—			—			(198,688	)		—
Realized gain (loss) on natural gas positions		(22,652	)		10,352			(25,020	)		33,064
Realized gain (loss) on NGL positions		(20,979	)		3,044			(45,146	)		13,733
Realized loss on interest hedges		(351	)		(3,704	)		(7,373	)		(8,670	)

Total realized gain (loss)		(93,103	)		41,941			(391,334	)		157,006

Unrealized gain (loss) on commodity hedges		(189,119	)		(111,248	)		(501,045	)		142,750
Unrealized gain (loss) on interest hedges		—			2,375			7,347			24

Total unrealized gain (loss)		(189,119	)		(108,873	)		(493,698	)		142,774

Total gain (loss) on derivatives	$	(282,222	)	$	(66,932	)	$	(885,032	)	$	299,780

NOTE 5 – FAIR VALUE MEASUREMENTS

GAAP 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 (exit price). Generally, the determination of fair value requires the use of significant judgment and different approaches and models under varying circumstances. Under a market-based approach, we consider prices of similar assets, consult with brokers and experts or employ other valuation techniques. Under an income-based approach, we generally estimate future cash flows and then discount them at a risk-adjusted rate. We classify the inputs used to measure the fair value of our financial assets and liabilities into the following hierarchy:

Level 3: Unobservable inputs that reflect management’s best estimates and assumptions of what market participants would use in measuring the fair value of an asset or liability.

Recurring Fair Value Measurements

The following table presents the location and fair value of our derivative assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2021 and December 31, 2020 by level within the fair value hierarchy:


	Fair Value Measurement Using

	Level 1		Level 2			Level 3		Total

	(in thousands)
September 30, 2021
Financial assets:
Derivative assets	$	—	$	2,015		$	—	$	2,015
Financial liabilities:
Derivative liabilities	$	—	$	(493,169	)	$	—	$	(493,169	)
December 31, 2020
Financial assets:
Derivative assets	$	—	$	87,090		$	—	$	87,090
Financial liabilities:
Derivative liabilities	$	—	$	(84,162	)	$	—	$	(84,162	)

See Note 4 – Derivatives for more information.

Non-Recurring Fair Value Measurements

Certain nonfinancial assets and liabilities are measured at fair value on a non-recurring basis. We utilize fair value measurement on a non-recurring basis to value our oil and natural gas properties when the carrying value of such property exceeds the respective undiscounted future cash flows. For the nine months ended September 30, 2020, we recorded impairment expense of $234.0 million in our unaudited combined and consolidated statements of operations related to the write down of our oil and natural gas properties to their fair value. The fair value was determined using a discounted cash flow model based on the expected present value of the future net cash flows from our oil and natural gas reserves. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include estimates of future prices, production costs, development expenditures, anticipated production, appropriate risk-adjusted discount rates, and other relevant data.

Other Fair Value Measurements

The carrying value of cash, accounts receivable, accounts payable and accrued liabilities approximate their fair values due to the short-term maturities of these instruments. Our long-term debt obligations under our New Credit Agreement also approximate fair value because the associated variable rate of interest is market based. The fair value of the notes (as defined below) as of September 30, 2021 was approximately $517.5 million based on quoted market prices.

NOTE 6 – ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Accounts payable and accrued liabilities consisted of the following as of September 30, 2021 and December 31, 2020:


	September 30, 2021		December 31, 2020

	(in thousands)
Accounts payable and accrued liabilities:
Accounts payable	$	47,838	$	15,019
Accrued lease operating expense		22,959		20,126
Accrued asset operating expense		1,774		3,591
Accrued capital expenditures		28,942		11,793
Accrued general and administrative		12,002		9,549
Accrued gathering, transportation and marketing		15,761		13,449
Accrued interest expense		15,954		643
Accrued tax expense		9,707		1,802
Other		5,328		4,716

Total accounts payable and accrued liabilities	$	160,265	$	80,688

NOTE 7 – DEBT

$500.0 million Senior Notes Issuance

On May 6, 2021, Independence Energy Finance LLC, our wholly owned subsidiary, issued $500.0 million aggregate principal amount of 7.250% Senior Notes due 2026 (the “notes”). The notes bear interest at an annual rate of 7.250%, which is payable on May 1 and November 1 of each year and mature on May 1, 2026.

The notes are our senior unsecured obligations and the notes and the related guarantees rank equally in right of payment with the borrowings under our New Credit Agreement and any of our other future senior indebtedness and senior to any of our future subordinated indebtedness. The notes are guaranteed on a senior unsecured basis by each of our existing and future subsidiaries that will guarantee our New Credit Agreement. The notes and the guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our New Credit Agreement) to the extent of the value of the collateral securing such indebtedness and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the notes.

We may, at our option, redeem all or a portion of the notes at any time on or after May 1, 2023 at certain redemption prices. We may also redeem up to 40% of the aggregate principal amount of the notes before May 1, 2023 with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.250% of the principal amount of the notes being redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. In addition, prior to May 1, 2023, we may redeem some or all of the notes at a price equal to 100% of the principal amount thereof, plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but excluding, the redemption date.

If we experience certain kinds of changes of control accompanied by a ratings decline, holders of the notes may require us to repurchase all or a portion of their notes at certain redemption prices. The notes are not listed, and we do not intend to list the notes in the future, on any securities exchange, and currently there is no public market for the notes.

New Credit Agreement

Overview

In connection with the notes issuance, we entered into a senior secured reserve-based revolving credit agreement (as amended, restated, amended and restated or otherwise modified to date, the “New Credit Agreement”) with Wells Fargo Bank, N.A., as administrative agent for the lenders and letter of credit issuer, and the lenders from time to time party thereto. The initial committed amount and borrowing base under the New Credit Agreement are $500.0 million and $850.0 million, respectively. The New Credit Agreement matures on May 6, 2025. In September 2021, we entered into the first amendment to the New Credit Agreement. The first amendment to the New Credit Agreement, amongst other things, increased the committed amount from $500.0 million up to $700.0 million if we elect to increase the commitment before December 1, 2021. In addition, the first amendment to the New Credit Agreement increased our borrowing base to $1.3 billion, contingent upon the closing of the Contango Transaction. At September 30, 2021, we had $279.0 million of borrowings under the New Credit Agreement and $17.8 million in outstanding letters of credit.

The obligations under the New Credit Agreement remain secured by first priority liens on substantially all of the Company’s and the guarantors’ tangible and intangible assets, including without limitation, oil and natural gas properties and associated assets and equity interests owned by the Company and such guarantors. In connection with each redetermination of the borrowing base, the Company must maintain mortgages on at least 85% of the net present value, discounted at 9% per annum (“PV-9”) of the oil and natural gas properties that constitute borrowing base properties. The Company’s domestic direct and indirect subsidiaries are required to be guarantors under the New Credit Agreement, subject to certain exceptions.

The borrowing base is subject to semi-annual scheduled redeterminations on or about April 1 and October 1 of each year, as well as (i) elective borrowing base interim redeterminations at our request not more than twice during any consecutive 12-month period or the required lenders not more than once during any consecutive 12-month period and (ii) elective borrowing base interim redeterminations at our request following any acquisition of oil and natural gas properties with a purchase price in the aggregate of at least 5.0% of the then effective borrowing base. The borrowing base will be automatically reduced upon (i) the issuance of certain permitted junior lien debt and other permitted additional debt, (ii) the sale or other disposition of borrowing base properties if the aggregate PV-9 of such properties sold or disposed of is in excess of 5.0% of the borrowing base then in effect and (iii) early termination or set-off of swap agreements (a) the administrative agent relied on in determining the borrowing base or (b) if the value of such swap agreements so terminated is in excess of 5.0% of the borrowing base then in effect.

The combined proceeds from the notes issuance, New Credit Agreement and Noncontrolling Interest Carve-Out were used to fully repay all amounts outstanding under our Prior Credit Agreements (as defined below), which were then terminated upon the repayment of the remaining principal and accrued interest.

Interest

Borrowings under the New Credit Agreement bear interest at either a U.S. dollar alternative base rate (based on the prime rate, the federal funds effective rate or an adjusted London Interbank Offered Rate (“LIBOR”)), plus an applicable margin or LIBOR, plus an applicable margin, at the election of the borrowers. The applicable margin varies based upon our borrowing base utilization then in effect. The fee payable for the unused revolving commitments is 0.50% per year and is included within interest expense on our unaudited combined and consolidated statements of operations. Our weighted average interest rate on loan amounts outstanding as of September 30, 2021 was 3.125%.

Covenants

The New Credit Agreement contains certain covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity, commodity swap agreements, liens and other transactions without the adherence to certain financial covenants or the prior consent of our lenders. We are subject to (i) maximum leverage ratio and (ii) current ratio financial covenants calculated as of the last day of each fiscal quarter. The New Credit Agreement also contains representations, warranties, indemnifications and affirmative and negative covenants, including events of default relating to nonpayment of principal, interest or fees,

inaccuracy of representations or warranties in any material respect when made or when deemed made, violation of covenants, bankruptcy and insolvency events, certain unsatisfied judgments and change of control. If an event of default occurs and we are unable to cure such default, the lenders will be able to accelerate maturity and exercise other rights and remedies.

Letters of Credit

Prior Credit Agreements

Certain of our subsidiaries entered into various credit agreements (the “Prior Credit Agreements”) with syndicates of lenders with original expiration dates between 2022 and 2024. The amounts we were able to borrow under each of the Prior Credit Agreements was limited by a borrowing base, which was based on the oil and natural gas properties, proved reserves, total indebtedness, and other factors and was consistent with customary lending criteria. On May 6, 2021, we early terminated the Prior Credit Agreements with the proceeds from the issuance of the notes and the Noncontrolling Interest Carve-out and borrowings under our New Credit Agreement.

Debt Outstanding

The following table summarizes our debt outstanding as of September 30, 2021:


	As of September 30, 2021

	Debt Outstanding			Letters of Credit Issued		Borrowing Base		Maturity

	(in thousands)
New Credit Agreement	$	279,000		$	17,771	$	850,000		5/6/2025
7.25% Senior Notes due 2026		500,000			—		—		5/1/2026
Less: Unamortized discount and issuance costs		(13,469	)

Total long-term debt	$	765,531

NOTE 8 – ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligation (“ARO”) liabilities are based on our net ownership in wells and facilities and management’s estimate of the costs to abandon and remediate those wells and facilities together with management’s estimate of the future timing of the costs to be incurred. Accretion expense is recognized in Depreciation, depletion and amortization on the unaudited combined and consolidated statements of operations. The following table summarizes activity related to our ARO liabilities for the nine months ended September 30, 2021:


	Nine Months Ended September 30, 2021
	(in thousands)
Balance at beginning of period	$	109,615
Additions		966
Retirements		(945	)
Sale		(1,910	)
Noncontrolling Interest Carve-out		(3,769	)
Accretion expense		4,801

Balance at end of period		108,758
Less: current portion		(2,269	)

Balance at end of period, noncurrent portion	$	106,489

NOTE 9 – COMMITMENTS AND CONTINGENCIES

We are subject to extensive federal, state and local environmental laws and regulations. These laws and regulations regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. We believe we are currently in compliance with all applicable federal, state and local laws and regulations. Accordingly, no liability or loss associated with environmental remediation was recognized as of September 30, 2021 except for the following:

We were engaged with the Environmental Protection Agency (“EPA”) for alleged violations of the Federal Water Pollution Control Act, as amended, between 2016 and 2018. We have settled these allegations with the EPA and recorded $1.4 million as a liability and expense as of and for the year ended December 31, 2020, all of which was paid during the nine months ended September 30, 2021.

On August 19, 2021, Matthew Whitfield, a purported Contango stockholder, filed a complaint, captioned Whitfield v. Contango Oil & Gas Co., et al., No. 1:21-cv-07009, in the United States District Court for the Southern District of New York, against Contango, the members of the Contango board, Independence, OpCo, New PubCo, L Merger Sub and C Merger Sub (the “Whitfield Action”). The Whitfield Action alleges, among other things, that the registration statement on Form S-4 filed by New PubCo on July 26, 2021 in connection with the Transactions (the “Registration Statement”) is false and misleading and/or omits certain information allegedly material to Contango stockholders in violation of Sections 14(a) and 20(a) of the Securities and Exchange Act of 1934 (as amended, the “Exchange Act”) and Rule 14a-9 promulgated thereunder. Among other relief, the Whitfield Action seeks an injunction enjoining the Contango Transactions unless and until the defendants disclose the allegedly omitted material information, a rescission of the Transaction Agreement to the extent already implemented (or an award of rescissory damages), an order directing the defendants to account for all damages resulting from the alleged wrongdoing, and an award of plaintiff’s attorneys’ and experts’ fees and other relief. The allegations, claims, and relief sought in the Whitfield Action are substantially similar to other actions filed by purported Contango stockholders related to the Contango Transaction, and the Whitfield Action has been consolidated with other such actions.

Independence believes that the Whitfield Action is without merit and, along with the individual and other defendants intend to defend against the Whitfield Action; however, Independence cannot predict the amount of time and expense that will be required to resolve the Whitfield Action nor its outcome. Additional lawsuits arising out of or related to the Contango Transaction may also be filed in the future. At September 30, 2021, we had no amounts reserved on our consolidated balance sheet related to this matter.

Oil Gathering Agreement

In connection with the execution of an oil gathering agreement with a midstream service provider, we received ownership in a Series D class of equity in the midstream service provider. The Series D units do not give us voting or other control rights but do provide us with an incentive distribution right if other unit classes receive distributions equal to contributed capital plus targeted rates of return. We account for the Series D units through the fair value option available under the FASB’s Accounting Standards Codification (“ASC”) 825, Financial Instruments. As of September 30, 2021 and December 31, 2020, we have concluded the fair value of our investment is not material, based on the nature of the Series D units and overall risk inherent in receiving future cash flows given the stage of development of the entity and required return hurdles.

Carbon Dioxide Purchase Agreement

We assumed one take-or-pay carbon dioxide purchase agreement as part of a prior acquisition. The agreement includes a minimum volume commitment to purchase carbon dioxide at a price stipulated in the contract. The agreement provides carbon dioxide for use in our enhanced recovery projects in certain of our properties. The daily minimum volume commitments are 140 MMcf per day from June 2021 to May 2026, with the commitment effectively ending in May 2026. We expect to purchase more carbon dioxide through the end of the agreement in 2026 than our minimum volume commitments, and, in accordance with the agreement, if we do not meet our minimum volume commitments for a year or years, we can make up the volumes in future years through 2029 as long as we pay for our minimum volumes each year. As of September 30, 2021, we have met required minimum volumes.

Oil and Natural Gas Transportation and Gathering Agreements

We have entered into certain oil and natural gas transportation and gathering agreements with various pipeline carriers. Under these agreements, we are obligated to ship minimum daily quantities or pay for any deficiencies at a specified rate. We are also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity that we utilize. If we do not utilize the capacity, we can release it to others, thus reducing our potential liability. We recognized $1.7 million and $12.4 million of transportation expense in our unaudited combined and consolidated statements of operations related to minimum volume deficiencies for the three months ended September 30, 2021 and 2020, respectively. For the nine months ended September 30, 2021 and 2020, we recognized $4.1 million and $13.6 million, respectively, of transportation expense in our unaudited combined and consolidated statements of operations related to minimum volume deficiencies.

The following table summarizes our future commitments related to these oil and natural gas transportation and gathering agreements as of September 30, 2021:


	As of September 30, 2021
	(in thousands)
2021	$	27,191
2022		103,347
2023		77,635
2024		62,574
2025		57,548
Thereafter		93,667

Total minimum future commitments	$	421,962

NOTE 10 – EQUITY BASED PAYMENT ARRANGEMENTS

Overview

Certain of our subsidiaries have entered into award agreements to grant profits interests and other incentive awards to employees and non-employees. These awards may contain certain service-, performance- and market-based vesting conditions, which are further discussed below.

DJ Basin Acquisition share-based payments

In exchange for services provided in connection with the DJ Basin Acquisition (see Note 3 - Acquisitions and Divestitures for more information), one of our subsidiaries issued liability and equity-classified profits interests awards. Compensation cost for these awards of $3.4 million was capitalized as part of the acquisition costs of the DJ Basin Acquisition. These awards contain no vesting conditions and are classified as other liabilities (in the case of the liability-classified awards) and noncontrolling interests (in the case of the equity-classified awards) in our unaudited combined and consolidated financial statements.

The liability-classified awards are subject to a put option, which allows the grantee to put the shares to us after three years, or earlier upon certain contingent conditions. As the settlement of the shares is outside of our control, the awards are classified as other liabilities in our unaudited consolidated balance sheet. We recorded these awards at their fair value of $1.8 million on the date of the DJ Basin Acquisition and remeasure the value at the end of each reporting period. For the three and nine months ended September 30, 2021, we recognized $0.1 million and $0.3 million in compensation expense related to the remeasurement of the award.

The awards also contain a feature in which the grantee will receive distributions in excess of ownership upon achieving specified distribution thresholds. This feature is not puttable and was classified as noncontrolling interests in permanent equity at a fair value of $1.6 million on the date of the DJ Basin Acquisition.

Liability-classified share-based payments

Certain of our subsidiaries issue profits interests that are liability-classified awards in accordance with ASC 718 Compensation – Stock Compensation. These awards contain different vesting conditions ranging from market-based conditions that vest upon the achievement of certain return thresholds to time-based service requirements ranging from three to four years. Each of these profits interests are liability-classified due to their repurchase features. Compensation cost for these awards is presented within general and administrative expense with a corresponding credit to other long-term liabilities. The fair value of these awards is remeasured as of the end of each reporting period until settlement.

Incentive compensation cost for time-based, liability-classified share-based payments was $4.8 million and $0.2 million for the three months ended September 30, 2021 and 2020, respectively, and $12.7 million and $0.8 million for the nine months ended September 30, 2021 and 2020, respectively. Additionally, certain of our share-base payments were modified to allow terminated employees to retain their awards, which resulted in a reclassification of the awards from ASC 710 Compensation – General to equity classification under ASC 718 Compensation – Stock Compensation. We recognized share-based compensation expense of $0.1 million and $1.6 million during the three and nine months ended September 30, 2021 related to these reclassified awards. During the three and nine months ended September 30, 2021, we repurchased $1.4 million of our noncontrolling interest, of which $0.1 million related to the repurchase of equity-classified share-based awards. We paid cash of $0.8 million and $0.9 million to settle liability-classified share-based awards during the three and nine months ended September 30, 2021. There were no cash settlements of liability-classified share-based payments during the three and nine months ended September 30, 2020. Unrecognized compensation cost related to non-vested, time-based liability-classified awards was $0.8 million as of September 30, 2021 and is expected to be recognized over a weighted-average period of 0.5 years.

Our time-based, liability-classified awards were remeasured at fair value using a Monte Carlo simulation as of September 30, 2021. We estimated the expected term of each award considering various exit scenarios. Expected volatility was based on the average of historical and implied volatility of a set of comparable companies, adjusted for size and leverage. The risk-free rate used was based on the yields of U.S. Treasury instruments with comparable terms.

The fair value of the time-based, liability-classified awards that vested during the nine months ended September 30, 2021 using the fair value measurement as of September 30, 2021 was $7.6 million. During the nine months ended September 30, 2021, no market-based awards vested.

Incentive awards other than share based payments

Certain of our subsidiaries have also issued incentive awards that require continuous service in order to receive distributions but do not represent an equity interest. As these incentive awards are similar to a cash bonus plan, compensation cost is measured based on the present value of expected benefits that are probable of being paid and recognized over the period services are provided. Compensation cost is remeasured at each reporting period based on expected future benefits and is attributed over the performance period on a straight-line basis. We did not recognize any compensation cost for this type of incentive award for the three and nine months ended September 30, 2021 and 2020.

NOTE 11 – RELATED PARTY TRANSACTIONS

KKR

Pursuant to our management agreement (the “Management Agreement”) with an affiliate of KKR (the “Manager”), the Manager has agreed to provide us with management services and other assistance, including with respect to strategic planning, identifying acquisitions, screening and referring potential investments, recommending strategies for exit from investments, executing our authorized investments and providing such other assistance as we may require, such as preparing valuations and reports necessary or appropriate for our compliance with our

Amended & Restated Limited Liability Company Agreement, dated August 18, 2020 (the “LLC Agreement”). In the future, to the extent we raise additional equity capital through the issuance of our Class B units, compensation under the Management Agreement will become payable by us and will be recorded as general and administrative expense on our combined and consolidated financial statements. The Management Agreement has a perpetual term unless terminated by the mutual consent of us and the Manager or by the removal of the current Managing Member under our LLC Agreement.

We paid $1.6 million in fees to an affiliate of KKR related to the issuance of the notes in May 2021. As of September 30, 2021, we had a related party receivable of $2.5 million included within accounts receivable – affiliates and $2.1 million included within accounts payable – affiliates on our unaudited consolidated balance sheets.

FDL

Certain of our consolidated subsidiaries have entered into an Oil and Natural Gas Property Operating and Services Agreement (the “FDL Agreement”) with FDL Operating LLC (“FDL”). Pursuant to the FDL Agreement, FDL was engaged to manage the day-to-day operations of the business activities of certain of our consolidated subsidiaries, including allocating to us and other interest holders the production and sale of oil, natural gas and NGLs, collection and disbursement of revenues, operating expenses and general and administrative expenses in the respective oil and natural gas properties, and the payment of all capital costs associated with the ongoing operations of the oil and natural gas assets. As part of the engagement, FDL will then allocate the revenues, operating expenses, general and administrative expenses and cash collected to us and others as appropriate. We settle balances due to or due from FDL on a monthly basis. As of September 30, 2021 and December 31, 2020, we had a related party receivable from FDL of $2.9 million and net related party payable to FDL of $7.5 million, respectively, included within accounts receivable – affiliates and accounts payable – affiliates on our unaudited consolidated balance sheets. On September 29, 2021 we provided notice that we are terminating the FDL Agreement effective on March 31, 2022. During October 2021, as part of the termination principal terms, we agreed to pay up to $6.5 million in wind down costs and additional severance costs for certain qualifying, dedicated employees. We expect to deposit up to $6.5 million in escrow during the fourth quarter of 2021, of which any unused portion will be returned to us at the end of the wind down period.

On April 1, 2021, certain co-investors, including FDL management, exchanged 100% of their interests in our Barnett Basin natural gas assets for 9,508 of our Class A units, representing 0.77% of our consolidated ownership. Since we already consolidate the results of these assets, this transaction was accounted for as an equity transaction and reflected as a reclassification from noncontrolling interests to members’ equity with no gain or loss recognized on the exchange (the “April 2021 Exchange”). As of September 30, 2021, FDL’s management owns less than 0.15% of our Class A units and holds noncontrolling interests in certain of our consolidated subsidiaries.

RPM

An affiliate of KKR has entered into a Master Management Services Agreement (the “MSA”) with a subsidiary of RPM Energy Management Partnership L.P. (“RPM”) to act as the manager of certain mineral and non-operated assets controlled by our consolidated subsidiaries. Pursuant to the MSA and under management of certain KKR affiliated entities, RPM manages the day-to-day operations of the business activities of certain of our oil and natural gas properties. We reimburse RPM for all reasonable out-of-pocket expenses incurred for fulfilling its obligations under the MSA (“Allocable Overhead Costs”). The Allocable Overhead Costs are charged to us on an actual basis without mark-up or subsidy. As such, the Allocable Overhead Costs approximate reasonable market rates and are representative of the expenses that we would have incurred had we not entered into the MSA. We settle balances due to or due from RPM on a monthly basis.

As of September 30, 2021 and December 31, 2020 we had a payable due to RPM of $1.5 million and $1.7 million, respectively, included within accounts payable – affiliates on our unaudited consolidated balance sheets.

NOTE 12 – EARNINGS PER UNIT

We have two classes of equity in the form of Class A units and Class B units. Both Class A units and Class B units are considered common units, and distributions are made pro rata in accordance with each unit’s respective ownership percentage. As such, we apply the two-class method for purposes of calculating earnings per unit (“EPU”). Net income (loss) attributable to members is allocated to Class A units and Class B units in proportion to the pro rata ownership of each class after giving effect to distributions declared during the period, if any. There were no Class B units issued or outstanding during the periods presented.

As described in Note 1 – Organization and Basis of Presentation, our financial statements have been retrospectively recast to reflect the historical accounts of the Contributed Entities on a combined basis due to the Reorganization. The denominator for our computation of net income (loss) per unit for periods prior to the Reorganization is calculated based on the number of Class A units received by our parent as a result of the Reorganization.

The following table sets forth the computation of basic and diluted net income (loss) per unit:


	Three Months Ended September 30,						Nine Months Ended September 30,

	2021			2020			2021			2020

	(in thousands, except unit and per unit amounts)
Numerator:
Net income (loss)	$	(162,043	)	$	(101,005	)	$	(601,172	)	$	(46,442	)
Less: net (income) loss attributable to noncontrolling interests		1,476			31,015			15,368			61,008

Net income (loss) attributable to members	$	(160,567	)	$	(69,990	)	$	(585,804	)	$	14,566

Denominator:
Weighted-average Class A Units outstanding – basic and diluted		1,229,929			801,847			1,226,795			681,195
Net income (loss) per unit:
Class A Units – basic and diluted	$	(130.55	)	$	(87.29	)	$	(477.51	)	$	21.38

NOTE 13 – SUBSEQUENT EVENTS

Subsequent events have been evaluated through the date of issuance of these financial statements, and there have been no events subsequent to September 30, 2021, other than those items disclosed below or elsewhere in the notes, that would require additional adjustments to our disclosure in our financial statements.

Contango Transaction

In October 2021, we filed our amended Proxy with the SEC and subsequently the SEC declared our Proxy effective in November 2021. We closed the Contango Transaction on December 7, 2021.

Exhibit 99.3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Contango Oil & Gas Company

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Contango Oil & Gas Company (a Texas corporation) and subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of operations, cash flows, and shareholders’ equity for each of the two years in the period ended December 31, 2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.

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 Public Company Accounting Oversight Board (United States) (“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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such 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 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 critical audit matters does not alter in any way our opinion on the 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.

Depletion expense and impairment of oil and gas properties impacted by the Company’s estimation of proved reserves

As described further in Notes 2 and 5 to the financial statements, the Company accounts for its oil and gas properties using the successful efforts method of accounting which requires management to estimate reserve volumes and future net revenues to record depletion expense and to assess if there are indications the carrying value of certain properties exceed the fair value and if so, determine the fair value of its oil and gas properties to measure impairment. To estimate the volume of reserves and future net revenues, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties, and forecasting the timing and volume of production associated with the Company’s development plan for undeveloped properties. In addition, the estimation of reserves is also impacted by management’s judgments and estimates regarding the

financial performance of wells associated with reserves to determine if wells are expected, with reasonable certainty, to be economical under the pricing assumptions required in the estimation of depletion expense and impairment evaluation and measurements. We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense and the evaluation and measurement of impairment, as a critical audit matter.

The principal consideration for our determination that the estimation of reserves is a critical audit matter is that relatively minor changes in certain inputs and assumptions, which require a high degree of subjectivity necessary to estimate the volume and future revenues of the Company’s reserves, could have a significant impact on the measurement of depletion or impairment expense. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.

Our audit procedures related to the estimation of proved reserves included the following, among others.

•

We evaluated the level of knowledge, skill and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserves, and read the reserve reports prepared by the Company’s reservoir engineering specialists.

•

We tested the accuracy of the Company’s depletion calculations and impairment evaluation and measurement that included these proved reserve reports.

•

We evaluated sensitive inputs and assumptions used to determine reserve volumes and other cash flow inputs and assumptions derived from the Company’s accounting records. These assumptions included historical pricing differentials, current and future operating costs, estimated future capital costs, and ownership interests. We tested management’s process for determining the assumptions, including examining the underlying support on a sample basis for reasonableness and accuracy. Specifically, our audit procedures involved testing management’s assumptions as follows:

•

Compared the estimated pricing differentials used in the reserve reports to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;

•

Evaluated models used to estimate the future operating costs in the reserve reports and compared amounts to historical operating costs;

•

Evaluated the method used to determine the future capital costs and compared estimated future capital costs used in the reserve reports to amounts expended for recently drilled and completed wells;

•

Tested the ownership interests used in the reserve reports by inspecting land and title records;

•

Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve reports by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties; and

•

Applied analytical procedures to the forecasted production in the reserve reports by comparing to historical actual results and to the prior year or preceding period reserve reports.

/s/ GRANT THORNTON LLP

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

Houston, Texas

March 10, 2021

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except shares)


	December 31, 2020			December 31, 2019
CURRENT ASSETS:
Cash and cash equivalents	$	1,383		$	1,624
Accounts receivable, net		37,862			39,567
Prepaid expenses		3,360			1,191
Current derivative asset		2,996			3,819
Inventory		442			186
Deposits and other		763			—

Total current assets		46,806			46,387
PROPERTY, PLANT AND EQUIPMENT:
Oil and natural gas properties, successful efforts method of accounting:
Proved properties		1,274,508			1,306,916
Unproved properties		16,201			27,619
Other property and equipment		1,669			1,655
Accumulated depreciation, depletion, amortization and impairment		(1,190,475	)		(1,045,070	)

Total property, plant and equipment, net		101,903			291,120
OTHER NON-CURRENT ASSETS:
Investments in affiliates		6,793			6,766
Long-term derivative asset		497			357
Right-of-use lease assets		5,448			5,885
Debt issuance costs		1,782			3,311
Deposits		7,038			—

Total other non-current assets		21,558			16,319

TOTAL ASSETS	$	170,267		$	353,826

CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	83,970		$	104,593
Current derivative liability		1,317			3,951
Current asset retirement obligations		4,249			2,003

Total current liabilities		89,536			110,547
NON-CURRENT LIABILITIES:
Long-term debt		12,369			72,768
Long-term derivative liability		1,648			2,020
Asset retirement obligations		48,523			49,662
Lease liabilities		2,624			2,789

Total non-current liabilities		65,164			127,239

Total liabilities		154,700			237,786

COMMITMENTS AND CONTINGENCIES (NOTE 14)
SHAREHOLDERS’ EQUITY:
Series C convertible preferred stock, $0.04 par value, no shares authorized, issued and outstanding at December 31, 2020 and 2,700,000 shares authorized, issued and outstanding at December 31, 2019		—			108
Common stock, $0.04 par value, 400 million shares authorized, 173,830,390 shares issued and 173,737,816 shares outstanding at December 31, 2020, 128,985,146 shares issued and 128,977,816 shares outstanding at December 31, 2019		6,941			5,148
Additional paid-in capital		535,192			471,778
Treasury shares at cost (92,574 shares at December 31, 2020 and 7,330 shares at December 31, 2019)		(248	)		(18	)
Accumulated deficit		(526,318	)		(360,976	)

Total shareholders’ equity		15,567			116,040

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	170,267		$	353,826

The accompanying notes are an integral part of these consolidated financial statements.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)


	Year Ended December 31,
	2020			2019
REVENUES:
Oil and condensate sales	$	62,461		$	44,705
Natural gas sales		31,381			22,380
Natural gas liquids sales		17,078			9,427
Fee for service revenues		2,000			—

Total revenues		112,920			76,512

EXPENSES:
Operating expenses		72,847			33,205
Exploration expenses		11,594			1,003
Depreciation, depletion and amortization		30,032			39,807
Impairment & abandonment of oil and natural gas properties		168,802			128,290
General and administrative expenses		24,940			24,938

Total expenses		308,215			227,243

OTHER INCOME (EXPENSE):
Gain (loss) from investment in affiliates (net of income taxes)		27			742
Gain from sale of assets		4,501			518
Interest expense		(5,022	)		(8,596	)
Gain (loss) on derivatives, net		27,585			(3,357	)
Other income		3,609			1,848

Total other income		30,700			(8,845	)

NET LOSS BEFORE INCOME TAXES		(164,595	)		(159,576	)
Income tax provision		(747	)		(220	)

NET LOSS ATTRIBUTABLE TO COMMON STOCK	$	(165,342	)	$	(159,796	)

NET LOSS PER SHARE:
Basic	$	(1.20	)	$	(2.95	)
Diluted	$	(1.20	)	$	(2.95	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		137,522			54,136
Diluted		137,522			54,136

The accompanying notes are an integral part of these consolidated financial statements.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Year Ended December 31,
	2020			2019
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(165,342	)	$	(159,796	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		30,032			39,807
Impairment of oil and natural gas properties		168,732			126,964
Exploration expenditures - dry hole costs		10,455			—
Amortization of debt issuance costs		1,603			144
Deferred income taxes		—			424
Gain on sale of assets		(4,501	)		(518	)
Gain from investment in affiliates		(27	)		(742	)
Stock-based compensation		4,270			2,352
Unrealized loss (gain) on derivative instruments		(2,321	)		5,973
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable & other		1,463			(9,903	)
Decrease (increase) in prepaid expenses		(2,169	)		451
Increase in inventory		(256	)		—
Increase (decrease) in accounts payable & advances from joint owners		(6,279	)		10,739
Increase (decrease) in other accrued liabilities		(7,477	)		13,019
Decrease (increase) in income taxes receivable, net		281			(85	)
Increase (decrease) in income taxes payable, net		233			(153	)
Deposits and other		(7,801	)		(6,966	)

Net cash provided by operating activities	$	20,896		$	21,710

CASH FLOWS FROM INVESTING ACTIVITIES:
Oil & natural gas exploration & development expenditures	$	(21,689	)	$	(42,737	)
Acquisition of oil & natural gas properties		—			(112,075	)
Additions to furniture & equipment		(13	)		(53	)
Sale of oil and natural gas properties		349			10

Net cash used in investing activities	$	(21,353	)	$	(154,855	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under Credit Agreement	$	79,700		$	256,923
Repayments under Credit Agreement		(143,468	)		(244,154	)
Payroll Protection Program Loan		3,369			—
Net proceeds from equity offerings		60,919			125,710
Purchase of treasury stock		(230	)		(255	)
Debt issuance costs		(74	)		(3,455	)

Net cash provided by financing activities	$	216		$	134,769

NET CHANGE IN CASH AND CASH EQUIVALENTS	$	(241	)	$	1,624
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		1,624			—

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	1,383		$	1,624

The accompanying notes are an integral part of these consolidated financial statements.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

For the twelve months ended December 31, 2020

(in thousands, except share amounts)


	Preferred Stock						Common Stock					Additional Paid-in Capital			Treasury Stock			Accumulated Deficit			Total Shareholders’ Equity
	Shares			Amount			Shares			Amount		Additional Paid-in Capital			Treasury Stock			Accumulated Deficit			Total Shareholders’ Equity
Balance at December 31, 2019		2,700,000		$	108			128,977,816		$	5,148	$	471,778		$	(18	)	$	(360,976	)	$	116,040
Equity offering - common stock		—			—			—			—		(47	)		—			—			(47	)
Treasury shares at cost		—			—			(49,474	)		—		—			(157	)		—			(157	)
Restricted shares activity		—			—			77,485			3		(3	)		—			—			—
Stock-based compensation		—			—			—			—		350			—			—			350
Net loss		—			—			—			—		—			—			(105,255	)		(105,255	)

Balance at March 31, 2020		2,700,000		$	108			129,005,827		$	5,151	$	472,078		$	(175	)	$	(466,231	)	$	10,931

Equity offering - common stock		—			—			155,029			6		477			—			—			483
Conversion of preferred stock to common stock		(2,700,000	)		(108	)		2,700,000			108		—			—			—			—
Treasury shares at cost		—			—			(13,808	)		—		—			(23	)		—			(23	)
Restricted shares activity		—			—			149,709			6		(6	)		—			—			—
Stock-based compensation		—			—			—			—		265			—			—			265
Net loss		—			—			—			—		—			—			(28,034	)		(28,034	)

Balance at June 30, 2020		—		$	—			131,996,757		$	5,271	$	472,814		$	(198	)	$	(494,265	)	$	(16,378	)

Equity offering - common stock		—			—			8,900			—		(27	)		—			—			(27	)
Treasury shares at cost		—			—			(3,678	)		—		—			(8	)		—			(8	)
Restricted shares activity		—			—			1,011,699			41		(41	)		—			—			—
Stock-based compensation		—			—			—			—		1,764			—			—			1,764
Net loss		—			—			—			—		—			—			(6,805	)		(6,805	)

Balance at September 30, 2020		—		$	—			133,013,678		$	5,312	$	474,510		$	(206	)	$	(501,070	)	$	(21,454	)

Equity offering - common stock		—			—			40,645,891			1,626		58,883			—			—			60,509
Treasury shares at cost		—			—			(18,284	)		—		—			(42	)		—			(42	)
Restricted shares activity		—			—			96,531			3		(3	)		—			—			—
Stock-based compensation		—			—			—			—		1,802			—			—			1,802
Net loss		—			—			—			—		—			—			(25,248	)		(25,248	)

Balance at December 31, 2020		—		$	—			173,737,816		$	6,941	$	535,192		$	(248	)	$	(526,318	)	$	15,567

The accompanying notes are an integral part of these consolidated financial statements.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

For the twelve months ended December 31, 2019

(in thousands, except share amounts)


	Preferred Stock						Common Stock						Additional Paid-in Capital			Treasury Stock			Accumulated Deficit			Total Shareholders’ Equity
	Shares			Amount			Shares			Amount			Additional Paid-in Capital			Treasury Stock			Accumulated Deficit			Total Shareholders’ Equity
Balance at December 31, 2018		—		$	—			34,158,492		$	1,573		$	339,981		$	(129,030	)	$	(72,135	)	$	140,389
Equity offering - common stock		—			—			—			—			(86	)		—			—			(86	)
Treasury shares at cost		—			—			(49,415	)		—			—			(186	)		—			(186	)
Restricted shares activity		—			—			307,650			12			(12	)		—			—			—
Stock-based compensation		—			—			—			—			1,052			—			—			1,052
Net loss		—			—			—			—			—			—			(8,618	)		(8,618	)

Balance at March 31, 2019		—		$	—			34,416,727		$	1,585		$	340,935		$	(129,216	)	$	(80,753	)	$	132,551

Equity offering - common stock		—			—			—			—			45			—			—			45
Treasury shares at cost		—			—			(16,133	)		—			—			(50	)		—			(50	)
Restricted shares activity		—			—			42,249			2			(2	)		—			—			—
Stock-based compensation		—			—			—			—			585			—			—			585
Net loss		—			—			—			—			—			—			(4,961	)		(4,961	)

Balance at June 30, 2019		—		$	—			34,442,843		$	1,587		$	341,563		$	(129,266	)	$	(85,714	)	$	128,170

Equity offering - preferred stock		789,474			32			—			—			7,420			—			—			7,452
Equity offering - common stock		—			—			45,922,870			2,058			44,181			—			—			46,239
Treasury shares at cost		—			—			5,524,498			(221	)		—			129,266			(129,045	)		—
Treasury shares reissuance		—			—			(25,748	)		(1	)		1			—			—			—
Stock-based compensation		—			—			—			—			558			—			—			558
Net loss		—			—			—			—			—			—			(7,838	)		(7,838	)

Balance at September 30, 2019		789,474		$	32			85,864,463		$	3,423		$	393,723		$	—		$	(222,597	)	$	174,581

Equity offering - preferred stock		3,802,838			152			—			—			26,154			—			—			26,306
Equity offering - common stock		—			—			19,000,000			760			44,942			—			—			45,702
Conversion of preferred stock to common stock		(1,892,312	)		(76	)		18,923,120			757			(629	)		—			—			52
Treasury shares at cost		—			—			(7,330	)		—			—			(18	)		—			(18	)
Restricted shares activity		—			—			(27,437	)		(1	)		1			—			—			—
Stock-based compensation		—			—			—			—			158			—			—			158
Will Energy and Juneau acquisitions		—			—			5,225,000			209			7,429			—			—			7,638
Net loss		—			—			—			—			—			—			(138,379	)		(138,379	)

Balance at December 31, 2019		2,700,000		$	108			128,977,816		$	5,148		$	471,778		$	(18	)	$	(360,976	)	$	116,040

The accompanying notes are an integral part of these consolidated financial statements.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Business

Contango Oil & Gas Company (collectively with its subsidiaries, “Contango” or the “Company”) is a Fort Worth, Texas based independent oil and natural gas company. The Company’s business is to maximize production and cash flow from its offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore properties primarily located in Oklahoma, Texas, Wyoming and Louisiana and use that cash flow to explore, develop and acquire oil and natural gas properties across the United States.

The following table lists the Company’s primary producing areas as of December 31, 2020:


Location		Formation
Offshore Gulf of Mexico		Offshore Louisiana - water depths less than 300 feet
Central Oklahoma		Mississippian, Woodford, Oswego, Cottage Grove, Chester, Cleveland and Red Fork
Western Anadarko		Tonkawa, Cottage Grove, Cleveland, Marmaton, Chase Sandstone, Morrow, Chester and Oswego
West Texas		Wolfcamp A and B
Other Onshore (TX, LA, WY)		Woodbine, Lewisville, Buda, Georgetown, Eagleford, and Muddy Sandstone

Impact of the COVID-19 Pandemic

A novel strain of the coronavirus (“COVID-19”) surfaced in late 2019 and has spread, and continues to spread, around the world, including to the United States. In March 2020, the World Health Organization declared COVID-19 a pandemic, and the President of the United States declared the COVID-19 pandemic a national emergency. The COVID-19 pandemic has significantly affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the COVID-19 pandemic has resulted in travel restrictions, business closures and other restrictions that have disrupted the demand for oil throughout the world and, when combined with the oil supply increase attributable to the battle for market share among the Organization of Petroleum Exporting Countries (“OPEC”), Russia and other oil producing nations, resulted in oil prices declining significantly beginning in late February 2020. While there has been a modest recovery in oil prices, the length of this demand disruption is unknown, and there is significant uncertainty regarding the long-term impact to global oil demand, which negatively impacted the Company’s results of operations and planned 2020 capital activities. Due to the extreme volatility in oil prices and the impact of COVID-19 on the financial condition of our upstream peers, the Company suspended its drilling program in the Southern Delaware Basin in the first quarter of 2020 and focused on certain measures that included, but were not limited to, the following:

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work from home initiatives for all but critical staff and the implementation of social distancing measures;

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a company-wide effort to cut costs throughout the Company’s operations;

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utilization of the Company’s available storage capacity to temporarily store a portion of its production for later sale at higher prices when advantageous to do so (such as the approximate 50,000 barrels of second quarter oil production we stored and sold during the third quarter of 2020 at higher oil prices);

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suspension of any further plans for operated onshore and offshore drilling in 2020;

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pursuit of additional “fee for service” opportunities similar to the Management Services Agreement entered into in June 2020 with Mid-Con Energy Partners, LP (“Mid-Con”) (NASDAQ:MCEP), which was terminated at the closing of the Mid-Con Acquisition (as defined below) between the Company and Mid-Con on January 21, 2021); and

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potential acquisitions of PDP-heavy assets, with attractive, discounted valuations, in stressed/distressed scenarios or from non-industry owners, such as the Silvertip Acquisition (as defined below).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

From the Company’s initial entry into the Southern Delaware Basin in 2016 and through early 2019, the Company was focused on the development of its initial 6,500 net acre position in Pecos County, Texas (“Bullseye”), and in December 2018, the Company purchased an additional 4,200 gross operated (1,700 net) acres and 4,000 gross non-operated (200 net) acres to the northeast of its existing acreage (“NE Bullseye”). Contango’s 2019 drilling program included the completion of one well previously drilled in the Bullseye area, the drilling and completion of a second Bullseye well, and the drilling and completion of three wells in the NE Bullseye area. In December 2019, the Company began completion operations on its fourth NE Bullseye well, which began producing in January 2020, and then suspended further drilling in the area in response to the dramatic decline in oil prices. As of December 31, 2020, the Company was producing from 18 wells over its approximate 16,200 gross operated (7,500 company net) acre position in West Texas, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations.

In September 2019, the Company entered into unrelated purchase agreements with Will Energy Corporation (“Will Energy”) and White Star Petroleum, LLC and certain of its affiliates (collectively, “White Star”) to purchase certain producing assets and undeveloped acreage, primarily in Oklahoma. These transactions closed during the three months ended December 31, 2019, (the “Will Energy Acquisition” and “White Star Acquisition”) and were transformative, as production from these acquisitions represented approximately 70% of the Company’s total net production for the year ended December 31, 2020. See Note 4 – “Acquisitions and Dispositions” for more information. In conjunction with the White Star Acquisition, the Company entered into a new revolving credit agreement with JPMorgan Chase Bank, N.A. and other lenders (the “Credit Agreement”). In connection with the entry into the Credit Agreement, the Company repaid all obligations outstanding on, and terminated, its previous credit agreement with Royal Bank of Canada, which matured on October 1, 2019. The Credit Agreement has since been amended to increase the number of lenders from three to nine, and among other things, to adjust the borrowing base to $130.0 million on January 21, 2021 and $120.0 million on March 31, 2021. See Note 13 – “Long-Term Debt” for more information.

The Company completed two stock offerings in the third quarter of 2019. The Company completed an underwritten public offering (the “September 2019 Public Offering”) of 51,447,368 shares of common stock (of which 5,524,498 were reissued treasury shares) for net proceeds of approximately $46.2 million, after deducting the underwriting discount and fees and expenses. Net proceeds from the September 2019 Public Offering were used to fund the cash portion of the purchase price for the Will Energy Acquisition and to repay borrowings outstanding under the Company’s former revolving credit facility to provide incremental liquidity to support the Company’s planned acquisition efforts. In conjunction with the September 2019 Public Offering, the Company also entered into a purchase agreement with affiliates of John C. Goff, a director and significant shareholder, and current chairman of the Company, to issue and sell in a private placement (the “Series A Private Placement”) 789,474 shares of Series A contingent convertible preferred stock, which resulted in net proceeds of approximately $7.5 million.

The Company completed two additional stock offerings in the fourth quarter of 2019. In connection with the closing of the White Star Acquisition in November 2019, the Company completed a private placement of 1,102,838 shares of Series B contingent convertible preferred stock of the Company, which resulted in net proceeds of approximately $21.0 million (the “Series B Private Placement”). Net proceeds from the Series A Private Placement were used to fund a portion of the purchase price and related transaction expenses for the Will Energy Acquisition, and net proceeds from the Series B Private Placement were used to fund a portion of the purchase price and related transaction expenses for the White Star Acquisition. In December 2019, the Company also completed a private placement of 19,000,000 shares of common stock for net proceeds of approximately $45.7 million, after deducting the underwriting discount and fees and expenses (the “December 2019 Offering”). In conjunction with the December 2019 Offering, the Company also completed a private placement of 2,340,000 shares of Series C contingent convertible preferred stock (the “Series C Private Placement”) with affiliates of Mr. Goff, Wilkie S. Colyer, Jr., the Company’s chief executive officer, and others, which resulted in net proceeds of approximately $5.6 million. An additional 360,000 Series C contingent convertible preferred shares were issued in a private placement to the placement agents for the December 2019 Offering and Series C Private Placement, as partial consideration for their services in those offerings. Net proceeds from the December 2019 Offering and Series C Private Placement were used for general corporate purposes, including capital expenditures under the Company’s Joint Development Agreement with Juneau Oil & Gas, LLC (discussed below).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In December 2019, the Company obtained approval from the holders of a majority of the voting power of the Company’s capital stock to increase the number of common shares authorized for issuance from 100,000,000 to 200,000,000 common shares, at which time the Series A preferred shares automatically converted into 7,894,740 shares of common stock, the Series B preferred shares automatically converted into 11,028,380 shares of common stock, and the outstanding preferred shares were cancelled.

In December 2019, the Company entered into a Joint Development Agreement with Juneau Oil & Gas, LLC (“Juneau”), which provides the Company the right to acquire an interest in up to six of Juneau’s exploratory prospects located in the Gulf of Mexico. The first such exploratory prospect acquired by the Company, located in the Grand Isle Block 45 Area in the shallow waters off of the Louisiana coastline, was determined to be unsuccessful in June 2020. The Company is currently evaluating for future testing a number of exploratory prospects included in the Joint Development Agreement, including its Boss Hogg prospect located in the Eugene Island 298 Area in the shallow waters off of the Louisiana coastline. The Company’s strategy and timing on the testing of the Boss Hogg will be determined during the year based on regulatory considerations, some of which are fluid at this time, and on operational considerations, including the availability of appropriate equipment.

Following the reduction in the Company’s drilling program in the latter half of 2019, which then led to the suspension of onshore drilling in the first quarter of 2020, the Company continued to identify opportunities for cost reductions and operating efficiencies in all areas of its operations, while also searching for new resource acquisition opportunities. Acquisition efforts have been, and will continue to be, focused on PDP-heavy assets where the Company might also be able to leverage its geological and operational experience and expertise to reduce operating expenses, enhance production and identify and develop additional drilling opportunities that the Company believes will enable it to economically grow production and add reserves.

On June 5, 2020, the Company announced the addition of a new corporate business line that includes offering a property management service (or a “fee for service”) for oil and natural gas companies with distressed or stranded assets, or companies with a desire to reduce administrative costs by engaging a contract operator of its oil and natural gas assets. As part of this service offering, the Company entered into a Management Services Agreement (“MSA”) with Mid-Con, effective July 1, 2020, to provide services as contract operator of record on Mid-Con’s oil and natural gas properties, along with certain administrative and management services, in exchange for an annual services fee of $4 million, paid ratably over the twelve month period, plus reimbursement of certain costs and expenses, a deferred fee of $166,666 per month for each month that the agreement is in effect (not to exceed $2 million), to be paid in a lump sum upon termination of the agreement, and warrants to purchase a minority equity ownership in Mid-Con. In connection with the Company’s acquisition of Mid-Con on January 21, 2021, the MSA was terminated, the deferred fee obligation was forgiven, and the warrants were cancelled. See Note 4 – “Acquisitions and Dispositions” for more information. The Company recorded $2.0 million in revenue during the year ended December 31, 2020 related to this MSA with Mid-Con, which is included in “Fee for services revenue” in the Company’s consolidated statements of operations.

On June 8, 2020, the stockholders of the Company, at the Company’s 2020 Annual Meeting of Stockholders, approved an amendment (the “Charter Amendment”) to its Amended and Restated Certificate of Formation with the Secretary of State of the State of Texas to increase the number of authorized shares of common stock, par value of $0.04 per share, of the Company from 200,000,000 shares to 400,000,000 shares, and also approved the conversion of the 2,700,000 shares of the Series C contingent convertible preferred stock, par value $0.04 per share, into 2,700,000 shares of the Company’s common stock. On June 10, 2020, the Company filed the Charter Amendment with the Secretary of State of the State of Texas.

On June 24, 2020, the Company entered into an Open Market Sale Agreement (the “Sale Agreement”) among the Company and Jefferies LLC (the “Sales Agent”). Pursuant to the terms of the Sale Agreement, the Company may sell, from time to time through the Sales Agent in the open market, subject to satisfaction of certain conditions, shares of the Company’s common stock, having an aggregate public offering price of up to $100,000,000 (the “Shares”) (the “ATM Program”). The Company intends to use the net proceeds from any sales through the ATM Program, after deducting the Sales Agent’s commission and the Company’s offering expenses, to repay borrowings under its Credit Agreement and for general corporate purposes, including, but not limited to, acquisitions and exploratory drilling. Under the ATM Program, the Company sold 163,929 shares during the year ended December 31, 2020 for net proceeds of $0.5 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

On October 25, 2020, the Company and Mid-Con entered into an agreement and plan of merger providing for the acquisition by the Company of Mid-Con in an all-stock merger transaction in which Mid-Con would become a direct, wholly owned subsidiary of Contango (the “Mid-Con Acquisition”). On October 30, 2020, the Company entered into the Third Amendment (the “Third Amendment”) to its Credit Agreement under which, among other things, would increase the Company’s borrowing base from $75 million to $130.0 million, effective upon the closing of the Mid-Con Acquisition, with an automatic $10.0 million reduction in the borrowing base on March 31, 2021. The Mid-Con acquisition closed on January 21, 2021, with a total of 25,409,164 shares of Contango common stock issued. Upon closing of the Mid-Con Acquisition, the MSA was terminated, and the Company’s borrowing base was increased to $130.0 million. See Note 4 – “Acquisitions and Dispositions” and Note 13 – “Long-Term Debt” for further details.

Concurrently with the announcement of the Mid-Con Acquisition, the Company announced the execution of an agreement with a select group of institutional and accredited investors to sell 26,451,988 shares of common stock, which was completed on October 27, 2020. After deducting the underwriting discount and fees and expenses, the net proceeds were approximately $38.8 million, which were used for the Mid-Con Acquisition and for general corporate purposes, including the repayment of debt outstanding under the Company’s Credit Agreement.

On November 27, 2020, the Company entered into a purchase and sale agreement (the “Purchase Agreement”) with an undisclosed seller to acquire certain oil and natural gas properties located in the Big Horn Basin in Wyoming and Montana, in the Powder River Basin in Wyoming and in the Permian Basin in Texas and New Mexico (collectively the “Silvertip Acquisition”) for aggregate consideration of approximately $58 million. In connection with the execution of the Purchase Agreement, the Company paid $7.0 million as a deposit for its obligations under the Purchase Agreement, which is included in the consolidated balance sheet as of December 31, 2020. The Silvertip Acquisition closed on February 1, 2021, for a net consideration of approximately $53.2 million (including the $7.0 million deposit previously paid), after customary closing adjustments, including the results of operations during the period between the effective date of August 1, 2020 and the closing date. See Note 4 – “Acquisitions and Dispositions” for more information.

On December 1, 2020, the Company completed another private placement of 14,193,903 shares of common stock for net proceeds of approximately $21.7 million, after deducting the underwriting discount and fees and expenses. The net proceeds were used to fund the Silvertip Acquisition and for general corporate purposes, including the repayment of debt outstanding under the Company’s Credit Agreement.

2. Summary of Significant Accounting Policies

Basis of Presentation

The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly-owned subsidiaries are consolidated.

Other Investments

The Company has two seats on the board of directors of Exaro and has significant influence, but not control, over the company. As a result, the Company’s 37% ownership in Exaro is accounted for using the equity method. Under the equity method, the Company’s proportionate share of Exaro’s net income increases the balance of its investment in Exaro, while a net loss or payment of dividends decreases its investment. In the consolidated statements of operations, the Company’s proportionate share of Exaro’s net income is reported as a single line-item in “Gain from investment in affiliates” (net of income taxes).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods.

Revenue Recognition

Sales of oil, condensate, natural gas and natural gas liquids (“NGLs”) are recognized at the time control of the products are transferred to the customer. Based upon the Company’s past experience with its current purchasers and expertise in the market, collectability is probable, and there have not been payment issues with the Company’s purchasers over the past year or currently. Generally, the Company’s gas processing and purchase agreements indicate that the processors take control of the Company’s gas at the inlet of the plant, and that control of residue gas is returned to the Company at the outlet of the plant. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs. The Company delivers oil and condensate to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product.

When sales volumes exceed the Company’s entitled share, a production imbalance occurs. If production imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. Production imbalances have not had and currently do not have a material impact on the financial statements.

The Company records revenue in the month production is delivered to the purchaser. Settlement statements may not be received for 30 to 90 days after the date production is delivered, and therefore the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences between the Company’s estimates and the actual amounts received for product sales are generally recorded in the following month that payment is received. Any differences between the Company’s revenue estimates and actual revenue received historically have not been significant. The Company has internal controls in place for its revenue estimation accrual process. The Company will continue to review all new or modified revenue contracts on a quarterly basis for proper treatment.

Cash Equivalents

Cash equivalents are considered to be highly liquid investment grade debt investments having an original maturity of 90 days or less. As of December 31, 2020, the Company had $1.4 million in cash and cash equivalents, after transferring cash balances at the end of each day to reduce outstanding debt under the Company’s revolving Credit Agreement to minimize debt service costs. Under the Company’s cash management system, checks issued but not yet presented to banks by the payee frequently result in book overdraft balances for accounting purposes and are classified in accounts payable in the consolidated balance sheets. At December 31, 2020, accounts payable included $2.9 million in outstanding checks that had not been presented for payment. At December 31, 2019, accounts payable included $6.1 million in outstanding checks that had not been presented for payment.

Accounts Receivable

The Company sells oil, natural gas and NGLs to a limited number of customers. In addition, the Company participates with other parties in the operation of oil and natural gas wells. Substantially all of the Company’s accounts receivables are due from either purchasers of oil, natural gas and NGLs or participants in oil and natural gas wells for which the Company serves as the operator. Generally, operators of oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions and other pertinent factors. Amounts deemed uncollectible are charged to the allowance.

Accounts receivable allowance for doubtful accounts was $2.3 million and $1.0 million as of December 31, 2020 and 2019, respectively. At December 31, 2020 and 2019, the carrying value of the Company’s accounts receivable approximated fair value.

Oil and Natural Gas Properties - Successful Efforts

The Company follows the successful efforts method of accounting for its oil and natural gas activities. The Company’s application of the successful efforts method of accounting for its oil and natural gas exploration and production activities requires judgment as to whether particular wells are developmental or exploratory, since lease acquisition costs and all developmental costs are capitalized, whereas exploratory drilling costs are continuously capitalized until the results are determined. If proved reserves are not discovered, the drilling costs are expensed as exploration costs. Other exploratory costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred.

The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and natural gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive oil or natural gas field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas, and therefore, management must estimate the portion of seismic costs to expense as exploratory. During the quarter ended June 30, 2020, the Company drilled an unsuccessful exploratory well in the Gulf of Mexico, resulting in a charge of $10.5 million for drilling and prospect costs included in “Exploration expenses” in the Company’s consolidated statements of operations for the year ended December 31, 2020.

The evaluation of oil and natural gas leasehold acquisition costs included in unproved properties requires management’s judgment of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

Depreciation, depletion and amortization (“DD&A”) is calculated on a field basis using the unit of production method. Lease acquisition costs are amortized over remaining total proved reserves, and capitalized drilling and development costs of producing oil and natural gas properties, including related support equipment and facilities net of salvage value, are amortized over estimated proved developed oil and natural gas reserves. Upon sale or retirement of properties, the cost and related accumulated DD&A are eliminated from the accounts, and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least annually. Revisions are accounted for prospectively as changes in accounting estimates.

Other property and equipment are depreciated using the straight-line method over their estimated useful lives which range between three and 10 years.

Impairment of Oil and Natural Gas Properties

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

the assets in that field. If the estimated future undiscounted cash flows, based on the Company’s estimate of future reserves, oil and natural gas prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties. Additionally, the Company may use appropriate market data to determine fair value.

In the first quarter of 2020, the COVID-19 pandemic and the resulting deterioration in the global demand for oil, combined with the failure by OPEC and Russia to reach an agreement on lower production quotas until April 2020, caused a dramatic increase in the supply of oil, a corresponding decrease in commodity prices, and reduced the demand for all commodity products. The remainder of 2020 was further adversely affected by the continuation of the COVID-19 pandemic and the actions and measures that countries, states, localities, central banks, international financing and funding organizations, stock markets, businesses and individuals have taken to address the spread of the coronavirus and associated illnesses, the continued volatility of the oil and gas market, and the failure of OPEC and Russia to consistently and fully adhere to the quotas delineated in their agreement. Consequently, during the three months ended March 31, 2020, the Company recorded a $143.3 million non-cash charge for proved property impairment of its onshore properties related to the dramatic decline in commodity prices, the “PV-10” (present value, discounted at a 10% rate) of its proved reserves, and the associated change in its current development plans for its proved undeveloped locations. In the fourth quarter of 2020, the Company recorded an additional $21.1 million non-cash charge for proved property impairment, of which $15.6 million related to its offshore properties as a result of performance revisions in reserves and the decline in gas prices and production yield. The total non-cash proved property impairment recorded during the year ended December 31, 2020 was $164.4 million.

For the year ended December 31, 2019, the Company recognized non-cash proved property impairment expense of $117.8 million due to reserve revisions which resulted from the negative impact of performance and price related revisions to the present value of the Company’s year-end proved reserves, and the relationship of that value to the historical carrying cost of its assets on the balance sheet. Included in the impairment charge was $34.5 million related to the Company’s proved offshore Gulf of Mexico properties, primarily a result of performance revisions associated with the re-evaluation of the projected field costs and recoverable condensate volumes. In addition, the Company recognized onshore proved property impairment expense of $83.3 million. The onshore impairment was due primarily to price and performance revisions, which led to the re-evaluation of the economics and future drilling plans for the proved undeveloped locations, which then resulted in the elimination of certain proved undeveloped locations due to the SEC’s five-year development rule for such locations.

Unproved properties are reviewed quarterly to determine if there has been an impairment of the carrying value, with any such impairment charged to expense in the period. During the year ended December 31, 2020, the Company recorded a $4.3 million non-cash charge for unproved impairment expense related to undeveloped leases in its Central Oklahoma, Western Anadarko and Other Onshore regions. The Company recorded $2.6 million of this impairment expense in the first quarter of 2020, primarily related to leases the Company acquired from White Star and Will Energy in the fourth quarter of 2019, which were expiring in 2020, and the remaining $1.7 million of the impairment expense was recorded in the fourth quarter of 2020, due to leases expiring in 2021, all of which the Company has no plans to extend or develop as a result of the current commodity price environment and the Company’s continued focus on cost saving and production enhancing strategic initiatives.

During the year ended December 31, 2019, the Company recognized impairment expense of approximately $9.2 million related primarily to lease expirations, and near-term expirations, in the Company’s West Texas region.

Asset Retirement Obligations

Asset Retirement and Environmental Obligations (“ASC 410”) requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company records an asset retirement obligation (“ARO”) to reflect the Company’s legal obligation related to future plugging and abandonment of its oil

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

and natural gas wells, platforms and associated pipelines and equipment. The Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should these indicators suggest the estimated obligation may have materially changed on an interim basis, the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells, platforms, and associated pipelines and equipment as these obligations are incurred. The liability is accreted to its present value each period, and the capitalized cost is depleted over the useful life of the related asset. The accretion expense is included in DD&A expense.

The estimated liability is based on historical experience in plugging and abandoning wells. The estimated remaining lives of the wells is based on reserve life estimates and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free rate.

Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes in the risk-free rate, changes in the remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, the Company recognizes a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs. This gain or loss on abandonment is included in impairment and abandonment of oil and natural gas properties expense. See Note 12 – “Asset Retirement Obligation” for additional information.

Income Taxes

The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period. The Company reviews its tax positions quarterly for tax uncertainties. The Company did not have significant uncertain tax positions as of December 31, 2020. As described in Note 16 – “Income Taxes” with respect to Section 382 Ownership Change, the amount of unrecognized tax benefits did not change materially from December 31, 2019. The amount of unrecognized tax benefits may change in the next twelve months; however, the Company does not expect the change to have a significant impact on its financial position or results of operations. The Company includes interest and penalties in interest income and general and administrative expenses, respectively, in its consolidated statements of operations.

The Company files income tax returns in the United States and various state jurisdictions. The Company’s federal and state tax returns for 2009 – 2020 remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed.

Concentration of Credit Risk

Substantially all of the Company’s accounts receivable result from oil and natural gas sales or joint interest billings to a limited number of third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. See Note 3 – “Concentration of Credit Risk” for additional information.

Debt Issuance Costs

Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt. On September 17, 2019, the Company entered into the new revolving Credit Agreement with JPMorgan Chase Bank, N.A. and other lenders and incurred $1.8 million of arrangement and upfront fees in connection with the Credit Agreement. On November 1, 2019, the Credit Agreement was amended to add two additional lenders and increase the borrowing base thereunder, and the Company incurred an additional $1.6 million of debt issuance costs.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

On June 9, 2020, the Credit Agreement was amended to, among other things, reduce the borrowing base. No fees were incurred for the Second Amendment; however, during the three months ended June 30, 2020, the Company expensed $1.0 million of the debt issuance costs discussed above which originally were to be amortized over the life of the loan, due to the reduction in the borrowing base per the Second Amendment. On October 30, 2020, the Company entered into the Third Amendment to the Credit Agreement under which, among other things, increased the Company’s borrowing base from $75.0 million to $130.0 million, effective upon the closing of the Mid-Con Acquisition on January 21, 2021. The Company initially incurred $0.1 million in fees related to the Third Amendment during the three months ended December 31, 2020. During the year ended December 31, 2020, the Company amortized debt issuance costs of $1.6 million related to its Credit Agreement, including the $1.0 million mentioned above. As of December 31, 2020, the remaining balance of these debt issuance costs was $1.8 million, which will be amortized through September 17, 2024, with amortization expense included in the interest expense line item in the Company’s consolidated statements of operations.

In January 2021, the Company incurred an additional $0.9 million in fees related to the Third Amendment becoming effective on January 21, 2021, in connection with the closing of the Mid-Con Acquisition. These fees will also be amortized over the remaining term of the loan.

Stock-Based Compensation

The Company applies the fair value based method to account for stock based compensation. Under this method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the requisite service period, which generally aligns with the award vesting period. The Company classifies the benefits of tax deductions in excess of the compensation cost recognized for the options (excess tax benefit) as financing cash flows. The fair value of each restricted stock award is estimated as of the date of grant. The fair value of the performance stock units is estimated as of the date of grant using the Monte Carlo simulation pricing model.

Inventory

Inventory consists primarily of casing and tubing stored temporarily, which will be used for drilling or completion of wells. Inventory is recorded at the lower of cost or market using specific identification method.

Derivative Instruments and Hedging Activities

The Company accounts for its derivative activities under the provisions of ASC 815, Derivatives and Hedging (“ASC 815”). ASC 815 establishes accounting and reporting requirements that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. From time to time, the Company hedges a portion of its forecasted oil and natural gas production. Derivative contracts entered into by the Company have consisted of transactions in which the Company hedges the variability of cash flow related to a forecasted transaction using variable to fixed swaps and collars. The Company elected to not designate any of its derivative positions for hedge accounting. Accordingly, the net change in the mark-to-market valuation of these positions as well as all payments and receipts on settled derivative contracts are recognized in “Gain (loss) on derivatives, net” on the consolidated statements of operations for the years ended December 31, 2020 and 2019. Derivative instruments with settlement dates within one year are included in current assets or liabilities, whereas derivative instruments with settlement dates exceeding one year are included in non-current assets or liabilities. The Company calculates the asset or liability for current and non-current derivative instruments for each counterparty based on the settlement dates within the respective contracts. See Note 6 – “Derivative Instruments” for additional information.

Subsidiary Guarantees

Contango Oil & Gas Company, as the parent company (the “Parent Company”), filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Contango Resources, Inc., Contango Midstream Company, Contango Operators, Inc., Contaro Company, Contango Alta Investments, Inc. and any other of the Company’s future subsidiaries specified in the prospectus supplement (each a “Subsidiary Guarantor”) are Co-Registrants with the Parent Company under the registration statement, and the registration statement also registered guarantees of debt securities by the Subsidiary

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Guarantors. The Subsidiary Guarantors are wholly-owned by the Parent Company, either directly or indirectly, and any guarantee by the Subsidiary Guarantors will be full and unconditional. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. Finally, the Parent Company’s wholly-owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party.

Leases

The Company recognizes a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term on the Company’s consolidated balance sheet. The Company does not include leases with an initial term of twelve months or less on the balance sheet. The Company recognizes payments on these leases within “Operating expenses” on its consolidated statements of operations. The Company accounts for lease and non-lease contract components as a lease. The Company has procedures to review any new or modified contracts which contain a physical asset on a quarterly basis and determine if an arrangement is, or contains, a lease and determines the proper treatment. See Note 9 – “Leases” for additional information.

Recent Accounting Pronouncements

In June 2016, the FASB issued ASU 2016-13 - Financial Instruments - Credit Losses (“Topic 326”): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including the Company’s trade and joint interest billing receivables. Allowances are to be measured using a current expected credit loss model as of the reporting date that is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model that increases the allowance when losses are probable. Initially, ASU 2016-13 was effective for all public companies for fiscal years beginning after December 15, 2019. The FASB subsequently issued ASU 2019-04 (“ASU 2019-04”): Codification Improvements to Topic 326, Financial Instruments - Credit Losses, Topic 815, Derivatives, and Topic 825, Financial Instruments and ASU 2019-05 (“ASU 2019-05”): Financial Instruments - Credit Losses (Topic 326) - Targeted Transition Relief. ASU 2019-04 and ASU 2019-05 provide certain codification improvements related to the implementation of ASU 2016-13 and targeted transition relief consisting of an option to irrevocably elect the fair value option for eligible instruments. In November 2019, the FASB issued ASU 2019-10 - Financial Instruments - Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842): Effective Dates. This amendment deferred the effective date of ASU 2016-13 from January 1, 2020 to January 1, 2023 for calendar year-end smaller reporting companies, which includes the Company. The Company plans to defer the implementation of ASU 2016-13, and the related updates.

In November 2019, the FASB issued ASU 2019-12 - Income Taxes (“Topic 740”): Simplifying the Accounting for Income Taxes (“ASU 2019-12”). The amendments in ASU 2019-12 are part of an initiative to reduce complexity in accounting standards and simplify the accounting for income taxes by removing certain exceptions from Topic 740 and making minor improvements to the codification. The amendments in this update are effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations.

In March 2020, the FASB issued ASU 2020-04 - Reference Rate Reform (“Topic 848”): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). ASU 2020-04 provides optional guidance, for a limited period of time, to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. The amendments in ASU 2020-04 provide optional expedients and exceptions for applying US GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments in this ASU apply only to contracts, hedging relationships and other transactions that reference LIBOR, or another reference rate, expected to be discontinued because of reference rate reform. The Company is currently assessing the potential impact of ASU 2020-04 on its consolidated financial statements.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. Concentration of Credit Risk

The customer base for the Company is concentrated in the oil and natural gas industry. The Company’s largest three purchasers contributed approximately 36% of the Company’s total production revenues for the year ended December 31, 2020. The Company’s sales to these purchasers are not secured with letters of credit, and in the event of non-payment, the Company could lose up to two months of revenues. The loss of two months of revenues would have a material adverse effect on the Company’s financial position. However, we believe our current purchasers could be replaced by other purchasers under contracts with similar terms and conditions.

4. Acquisitions and Dispositions

Mid-Con Acquisition

On October 25, 2020, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement’) with Mid-Con and Mid-Con Energy GP, LLC, the general partner of Mid-Con (“Mid-Con GP”), pursuant to which Mid-Con will merge with and into Michael Merger Sub LLC, a Delaware limited liability company and a wholly-owned, direct subsidiary of the Company. The Mid-Con Acquisition, which closed on January 21, 2021, was unanimously approved by the conflicts committee of the board of directors of Mid-Con, by the full board of directors of Mid-Con, by the disinterested directors of the board of directors of the Company and was subject to shareholder and unitholder approvals and other customary conditions to closing. At the effective time of the Mid-Con Acquisition (the “Effective Time”), each common unit representing limited partner interests in Mid-Con issued and outstanding immediately prior to the Effective Time (other than treasury units or units held by Mid-Con GP) was converted automatically into the right to receive 1.75 shares of the Company’s common stock. A total of 25,409,164 shares of Contango common stock were issued at the closing of the Mid-Con Acquisition. As of January 21, 2021, John C. Goff, Chairman of the Board of Directors of the Company, beneficially owned approximately 56.4% of the common units of Mid-Con, and Travis Goff, John C. Goff’s son and the President of Goff Capital, Inc., served on the board of directors of the general partner of Mid-Con. The Company’s senior management team will run the combined company, and Contango’s board of directors will remain intact as the board of directors of the combined company. The combined company is headquartered in Fort Worth, Texas.

The Mid-Con acquisition will be accounted for as a business combination. Therefore, the purchase price will be allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by the Company in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for the timing and amount of future development and operating costs, future plugging and abandonment costs, and a risk adjusted discount rate. The Company expects to complete the purchase price allocation during the twelve-month period following the acquisition date. The following table sets forth the Company’s preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.


	Purchase Price Allocation
	(in thousands)
Consideration:
Cash	$	14,520
Exchange ratio of Contango shares for Mid-Con common units		1.75

Contango common stock to be issued to Mid-Con unitholders		25,409
Issue price		3.13

Total consideration	$	79,530

Liabilities Assumed:
Accounts payable	$	5,596
Other current liabilities		457
Revolving credit facility		68,487

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	Purchase Price Allocation
	(in thousands)
Asset retirement obligations		29,241

Total liabilities assumed	$	103,781

Assets acquired:
Cash and cash equivalents	$	776
Accounts receivable		4,398
Current derivative asset		3,141
Prepaid expenses		162
Proved oil and natural gas properties		172,607
Other property and equipment		730
Other non-current assets		1,497

Total assets acquired	$	183,311

The following unaudited pro forma combined condensed financial data for the years ended December 31, 2020 was derived from the historical financial statements of the Company after giving effect to the Mid-Con acquisition, as if it had occurred on January 1, 2020. The below information reflects pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including the depletion of the fair-valued proved oil and natural gas properties acquired from Mid-Con. The pro forma results of operations do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the assets acquired. The pro forma consolidated statement of operations data has been included for comparative purposes only, is not necessarily indicative of the results that might have occurred had the acquisition taken place on January 1, 2020 and is not intended to be a projection of future results.


(In thousands except for per share amounts)	Year Ended December 31, 2020
Revenues	$	150,569
Net loss	$	(188,178	)
Basic Earnings per share	$	(1.02	)
Diluted earnings per share	$	(1.02	)

Silvertip Acquisition

On November 27, 2020, the Company entered into the Purchase Agreement with an undisclosed seller to acquire certain oil and natural gas properties located in the Big Horn Basin in Wyoming and Montana, in the Powder River Basin in Wyoming and in the Permian Basin in Texas and New Mexico, for aggregate consideration of approximately $58 million in cash. In connection with the execution of the Purchase Agreement, the Company paid $7.0 million as a deposit for its obligations under the Purchase Agreement, which is included in the consolidated balance sheet as of December 31, 2020. The Silvertip Acquisition closed on February 1, 2021, and a balance of $46.2 million was paid upon closing, after customary closing adjustments, including the results of operations during the period between the effective date of August 1, 2020 and the closing date.

Juneau Joint Development Agreement

On December 23, 2019, the Company entered into a Joint Development Agreement with Juneau for aggregate consideration of $6.0 million, consisting of $1.69 million in cash and 1,725,000 shares of common stock of the Company. This agreement provides the Company the right to acquire an interest in up to six of Juneau’s exploratory prospects located in the Gulf of Mexico. The first such exploratory prospect acquired by the Company was the Iron Flea prospect located in the Grand Isle Block 45 Area in the shallow waters off of the Louisiana coastline, which was determined to be unsuccessful in June 2020. The Company is currently evaluating for future testing a number of exploratory prospects included in the Joint Development agreement, including the Boss Hogg prospect, located in the Eugene Island 298 Area in the shallow waters off of the Louisiana coastline. Management considers this Boss Hogg prospect to be an excellent complement to its PDP-oriented acquisition strategy and believes it could provide a very compelling economic value proposition, even in the current low oil price environment. The Company is currently working through regulatory considerations and operational factors, including the availability of appropriate equipment, in determining the ultimate strategy for, and timing on, the testing of that prospect.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

White Star Acquisition

On September 30, 2019, the Company entered into an asset purchase and sale agreement with White Star to acquire certain assets and liabilities, including approximately 306,000 net acres located in the STACK, Anadarko and Cherokee operating districts in Oklahoma. The closing of the White Star Acquisition occurred on November 1, 2019, for a total aggregate consideration of $132.5 million. Following adjustments for the results of operations for the period between the effective and closing dates, and other estimated, customary closing adjustments, the net consideration paid was approximately $95.7 million in cash.

The White Star Acquisition was accounted for as a business combination. Therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and natural gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and natural gas reserves, expectations for the timing and amount of future development and operating costs, future plugging and abandonment costs, and a risk adjusted discount rate. The following table sets forth the Company’s allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.


	Purchase Price Allocation
	(in thousands)
Consideration:
Cash	$	95,722

Total consideration	$	95,722

Liabilities Assumed:
Accounts payable	$	6,618
Revenue and royalties payable		11,165
Suspended revenue and royalties		22,011
Lease liabilities		3,614

Total liabilities assumed	$	43,408

Assets acquired:
Accounts receivable	$	18,037
Other current assets		1,413
Proved oil and natural gas properties		113,150
Unevaluated properties		2,611
Right-of-use lease assets		3,614
Other assets		305

Total assets acquired	$	139,130

The purchase price allocated to the assets acquired increased to $139.1 million from the previously reported $138.5 million due to an increase in the value of inventory acquired of $1.0 million and a decrease in the value of unevaluated properties acquired of $0.4 million. Approximately $21.4 million of revenues and $16.3 million of direct operating expenses attributed to the White Star Acquisition are included in the Company’s consolidated statements of operations for the period of the closing date on November 1, 2019 through December 31, 2019.

The following unaudited pro forma combined condensed financial data for the year ended December 31, 2019 was derived from the historical financial statements of the Company after giving effect to the White Star Acquisition, as if it had occurred on January 1, 2018. The below information reflects pro forma adjustments for the private placement of the Company’s Series B contingent convertible preferred stock and an increase in borrowings under the Company’s Credit Agreement, the proceeds of which were used to pay the purchase price of the White Star Acquisition, as well as pro forma adjustments based on then currently available information and certain assumptions that the Company believed were reasonable, including the depletion of the fair-valued proved oil and natural gas properties acquired from White Star and the exclusion of acquisition-related costs incurred by the

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Company of approximately $1.9 million for the year ended December 31, 2019. The pro forma results of operations do not include any cost savings or other synergies that may have resulted from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the assets acquired. In addition, the results of operations include non-cash impairment expense for White Star based on historical costs and not the fair value of the oil and natural gas properties acquired as reflected in the allocation of the purchase price. The pro forma financial data does not include the pro forma results of operations for any other acquisitions made during the periods presented, as they were not deemed material. The pro forma consolidated statements of operations data has been included for comparative purposes only, is not necessarily indicative of the results that might have occurred had the acquisition taken place on January 1, 2018 and is not intended to be a projection of future results.


(In thousands except for per share amounts)	Year Ended December 31, 2019
Revenues	$	207,530
Net loss	$	(265,760	)
Basic Earnings per share	$	(4.20	)
Diluted earnings per share	$	(4.20	)

Will Energy Acquisition

On September 12, 2019, the Company announced it entered into a contribution and purchase agreement with Will Energy to acquire approximately 155,900 net acres located in North Louisiana (8,000 net acres) and the Western Anadarko Basin in Western Oklahoma and the Texas Panhandle (147,900 net acres). Closing of the Will Energy Acquisition occurred on October 25, 2019, for a total aggregate consideration of $23 million. Following adjustments for sales of non-core, non-operated Louisiana properties by Will Energy prior to closing, the results of operations for the period between the effective and closing dates, and other estimated, customary closing adjustments, the net consideration paid consisted of $14.0 million in cash and 3.5 million shares of common stock.

Non-Core Assets Sales

During the years ended December 31, 2020 and 2019, the Company completed certain non-core asset sales to enhance its liquidity, eliminate marginal assets and reduce administrative costs. These asset sales provide some immediate liquidity and improve the Company’s balance sheet by removing future asset retirement obligations.

On June 1, 2020, the Company closed on the sale of certain producing and non-producing properties located in its Central Oklahoma and Western Anadarko regions. These non-core, marginally economic properties were a minor portion of the value of properties acquired from Will Energy and were sold in exchange for the buyer’s assumption of the plugging and abandonment liabilities of these properties and revenue held in suspense. The Company recorded a gain of $4.2 million as a result of the buyer’s assumption of the asset retirement obligations associated with the sold properties.

On April 1, 2020, the Company closed on the sale of certain non-producing properties located in its Central Oklahoma region. These properties were a minor portion of the value of properties acquired from White Star and were sold for approximately $0.5 million. The Company recorded a gain of $0.2 million as a result of the buyer’s assumption of the asset retirement obligations associated with the sold properties.

On July 1, 2019, the Company sold certain minor, non-core operated assets located in Frio and Zavala counties, Texas in exchange for the buyer’s assumption of the plugging and abandonment liabilities of the properties. The Company recorded a gain of $0.2 million after removal of the asset retirement obligations associated with the sold properties.

On June 10, 2019, the Company sold certain minor, non-core operated assets located in Lavaca and Wharton counties, Texas in exchange for the buyer’s assumption of the plugging and abandonment liabilities of the properties. The Company recorded a gain of $0.4 million related to the buyer’s assumption of the asset retirement obligations associated with the sold properties.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. Fair Value Measurements

Pursuant to ASC 820, Fair Value Measurements and Disclosures (“ASC 820”), the Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. ASC 820 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 (exit price). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have been no transfers between Level 1, Level 2 or Level 3.

Derivatives are recorded at fair value at the end of each reporting period. The Company records the net change in the fair value of these positions in “Gain (loss) on derivatives, net” in the Company’s consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 6 – “Derivative Instruments” for additional discussion of derivatives.

During the year ended December 31, 2020, the Company’s derivative contracts were with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. As such, the Company was exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company did not anticipate any nonperformance. The Company did not post collateral under any of these contracts as they are secured under the Credit Agreement or under unsecured lines of credit with non-bank counterparties.

Estimates of the fair value of financial instruments are made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s Credit Agreement approximates carrying value because the interest rate approximates current market rates and are re-set at least every three months. See Note 13 – “Long-Term Debt” for further information.

Fair value estimates used for non-financial assets are evaluated at fair value on a non-recurring basis and include oil and natural gas properties evaluated for impairment when facts and circumstances indicate that there may be an impairment. If the unamortized cost of properties exceeds the undiscounted cash flows related to the properties, the value of the properties is compared to the fair value estimated as discounted cash flows related to the risk-adjusted proved, probable and possible reserves related to the properties. Fair value measurements based on these inputs are classified as Level 3.

Impairments

Contango tests proved oil and natural gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

estimates or lower commodity prices. The Company estimates the undiscounted future cash flows expected in connection with the oil and natural gas properties on a field-by-field basis and compares such future cash flows to the unamortized capitalized costs of the properties. If the estimated future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties. Additionally, the Company may use appropriate market data to determine fair value. Because these significant fair value inputs are typically not observable, impairments of long-lived assets are classified as a Level 3 fair value measure.

Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period.

Asset Retirement Obligations

The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and natural gas properties. The factors used to determine fair value include, but are not limited to, estimated future plugging and abandonment costs and expected lives of the related reserves. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3 at inception.

6. Derivative Instruments

The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are utilized to hedge the Company’s exposure to price fluctuations and reduce the variability in the Company’s cash flows associated with anticipated sales of future oil and natural gas production. The Company typically hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. The Company believes that these derivative arrangements, although not free of risk, allow it to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of oil, natural gas and natural gas liquids sales. Moreover, because its derivative arrangements apply only to a portion of its production, the Company’s strategy provides only partial protection against declines in commodity prices. Such arrangements may expose the Company to risk of financial loss in certain circumstances. The Company continuously reevaluates its hedging programs in light of changes in production, market conditions and commodity price forecasts.

As of December 31, 2020, the Company’s oil and natural gas derivative positions consisted of “swaps”. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for oil and natural gas. The Company has also, from time to time, entered into “costless collars” derivative positions. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract, and a purchased put, which establishes a minimum price.

It is the Company’s practice to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. The Company did not post collateral under any of these contracts as they are secured under the Credit Agreement or under unsecured lines of credit with non-bank counterparties.

The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Gain (loss) on derivatives, net” on the consolidated statements of operations. See Note 5 – “Fair Value Measurements” for additional information.

The Company currently has derivative contracts in place to cover production periods through the first quarter of 2023, which include the hedges novated from Mid-Con and the additional hedges entered into in the first quarter of

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2021, as discussed below. These contracts include oil hedges for 2.1 MMBbls of 2021 production with an average floor price of $54.85 per barrel and 1.4 MMBbls of 2022 production with an average floor price of $50.24 per barrel. For natural gas, the Company’s derivative contracts include 12.4 Bcf of 2021 production with an average floor price of $2.62 per MMBtu and 10.1 Bcf of 2022 production with an average floor price of $2.60 per MMBtu. Approximately 97% of the Company’s hedges are swaps, and the Company has no three-way collars or short puts.

The Company had the following financial derivative contracts in place as of December 31, 2020:


Commodity	Period	Derivative	Volume/Month		Price/Unit				Fair Value
Oil	Jan 2021 - March 2021	Swap	19,000	Bbls	$	50.00	(1	)		78
Oil	April 2021 - July 2021	Swap	12,000	Bbls	$	50.00	(1	)		71
Oil	Aug 2021 - Sept 2021	Swap	10,000	Bbls	$	50.00	(1	)		39
Oil	Jan 2021 - July 2021	Swap	62,000	Bbls	$	52.00	(1	)		1,490
Oil	Aug 2021 - Sept 2021	Swap	55,000	Bbls	$	52.00	(1	)		434
Oil	Oct 2021 - Dec 2021	Swap	64,000	Bbls	$	52.00	(1	)		840
Oil	April 2022 - Oct 2022	Swap	25,000	Bbls	$	42.04	(1	)		(784	)
Natural Gas	Jan 2021 - March 2021	Swap	185,000	MMBtus	$	2.505	(2	)		(1	)
Natural Gas	April 2021 - July 2021	Swap	120,000	MMBtus	$	2.505	(2	)		(43	)
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	MMBtus	$	2.505	(2	)		(4	)
Natural Gas	Jan 2021 - March 2021	Swap	185,000	MMBtus	$	2.508	(2	)		(3	)
Natural Gas	April 2021 - July 2021	Swap	120,000	MMBtus	$	2.508	(2	)		(44	)
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	MMBtus	$	2.508	(2	)		(4	)
Natural Gas	Jan 2021 - March 2021	Swap	650,000	MMBtus	$	2.508	(2	)		(6	)
Natural Gas	April 2021 - Oct 2021	Swap	400,000	MMBtus	$	2.508	(2	)		(400	)
Natural Gas	Nov 2021 - Dec 2021	Swap	580,000	MMBtus	$	2.508	(2	)		(402	)
Natural Gas	April 2021 - Nov 2021	Swap	70,000	MMBtus	$	2.36	(2	)		(175	)
Natural Gas	Dec 2021	Swap	350,000	MMBtus	$	2.36	(2	)		(195	)
Natural Gas	Jan 2022 - March 2022	Swap	780,000	MMBtus	$	2.542	(2	)		(865	)
Natural Gas	April 2022 - July 2022	Swap	650,000	MMBtus	$	2.515	(2	)		252
Natural Gas	Aug 2022 - Oct 2022	Swap	350,000	MMBtus	$	2.515	(2	)		71
Natural Gas	Jan 2022 - March 2022	Swap	250,000	MMBtus	$	3.149	(2	)		179

Total net fair value of derivative instruments (in thousands)									$	528

(1)	Based on West Texas Intermediate oil prices.

(2)	Based on Henry Hub NYMEX natural gas prices.

The Company had the following financial derivative contracts in place as of December 31, 2019:


Commodity	Period	Derivative	Volume/Month	Price/Unit					Fair Value
Oil	Jan 2020 - June 2020	Swap	22,000	Bbls	$	57.74	(1	)		(289	)
Oil	July 2020 - Dec 2020	Swap	15,000	Bbls	$	57.74	(1	)		68
Oil	Jan 2020 - March 2020	Swap	2,700	Bbls	$	54.33	(1	)		(51	)
Oil	April 2020 - June 2020	Swap	2,500	Bbls	$	54.33	(1	)		(37	)
Oil	July 2020	Swap	5,500	Bbls	$	54.33	(1	)		(21	)
Oil	Aug 2020 - Oct 2020	Swap	2,500	Bbls	$	54.33	(1	)		(21	)
Oil	Nov 2020 - Dec 2020	Swap	3,500	Bbls	$	54.33	(1	)		(12	)
Oil	Jan 2020 - Feb 2020	Swap	42,500	Bbls	$	54.70	(1	)		(517	)
Oil	March 2020 - July 2020	Swap	37,500	Bbls	$	54.70	(1	)		(842	)
Oil	Aug 2020 - Dec 2020	Swap	35,000	Bbls	$	54.70	(1	)		(354	)
Oil	Jan 2020 - Feb 2020	Swap	42,500	Bbls	$	54.58	(1	)		(527	)
Oil	March 2020 - July 2020	Swap	37,500	Bbls	$	54.58	(1	)		(864	)
Oil	Aug 2020 - Dec 2020	Swap	35,000	Bbls	$	54.58	(1	)		(373	)
Oil	Jan 2020 - Oct 2020	Collar	3,442	Bbls	$	52.00 - 65.70	(1	)		18

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


Commodity	Period	Derivative	Volume/Month	Price/Unit					Fair Value
Oil	Jan 2021 - March 2021	Swap	19,000	Bbls	$	50.00	(1	)		(291	)
Oil	April 2021 - July 2021	Swap	12,000	Bbls	$	50.00	(1	)		(196	)
Oil	Aug 2021 - Sept 2021	Swap	10,000	Bbls	$	50.00	(1	)		(67	)
Oil	Jan 2021 - July 2021	Swap	62,000	Bbls	$	52.00	(1	)		(1,122	)
Oil	Aug 2021 - Sept 2021	Swap	55,000	Bbls	$	52.00	(1	)		(157	)
Oil	Oct 2021 - Dec 2021	Swap	64,000	Bbls	$	52.00	(1	)		(184	)
Natural Gas	Jan 2020 - March 2020	Swap	425,000	MMBtus	$	2.841	(2	)		856
Natural Gas	Jan 2020 - March 2020	Collar	225,000	MMBtus	$	2.45 - 3.40	(2	)		209
Natural Gas	April 2020 - July 2020	Swap	400,000	MMBtus	$	2.532	(2	)		493
Natural Gas	Aug 2020 - Oct 2020	Swap	40,000	MMBtus	$	2.532	(2	)		25
Natural Gas	Nov 2020 - Dec 2020	Swap	375,000	MMBtus	$	2.696	(2	)		134
Natural Gas	Jan 2020 - March 2020	Swap	300,000	MMBtus	$	2.53	(2	)		325
Natural Gas	April 2020 - July 2020	Swap	400,000	MMBtus	$	2.53	(2	)		490
Natural Gas	Aug 2020 - Dec 2020	Swap	350,000	MMBtus	$	2.53	(2	)		223
Natural Gas	Jan 2020 - March 2020	Swap	300,000	MMBtus	$	2.532	(2	)		327
Natural Gas	April 2020 - July 2020	Swap	400,000	MMBtus	$	2.532	(2	)		493
Natural Gas	Aug 2020 - Dec 2020	Swap	350,000	MMBtus	$	2.532	(2	)		226
Natural Gas	Jan 2021 - March 2021	Swap	185,000	MMBtus	$	2.505	(2	)		(78	)
Natural Gas	April 2021 - July 2021	Swap	120,000	MMBtus	$	2.505	(2	)		99
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	MMBtus	$	2.505	(2	)		4
Natural Gas	Jan 2021 - March 2021	Swap	185,000	MMBtus	$	2.508	(2	)		(75	)
Natural Gas	April 2021 - July 2021	Swap	120,000	MMBtus	$	2.508	(2	)		104
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	MMBtus	$	2.508	(2	)		4
Natural Gas	Jan 2021 - March 2021	Swap	650,000	MMBtus	$	2.508	(2	)		(268	)
Natural Gas	April 2021 - Oct 2021	Swap	400,000	MMBtus	$	2.508	(2	)		544
Natural Gas	Nov 2021 - Dec 2021	Swap	580,000	MMBtus	$	2.508	(2	)		20

Total net fair value of derivative instruments (in thousands)									$	(1,684	)

(1)	Based on West Texas Intermediate oil prices.

(2)	Based on Henry Hub NYMEX natural gas prices.

In addition to the above financial derivative instruments, the Company also had a costless swap agreement with a Midland WTI – Cushing oil differential swap price of $0.05 per barrel of oil. The agreement fixed the Company’s exposure to that differential on 12,000 barrels of oil per month for January 2020 through June 2020 and 10,000 barrels per month for July 2020 through December 2020. The fair value of this costless swap agreement was in a liability position of $0.1 million as of December 31, 2019.

The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2020 (in thousands).


	Gross			Netting (1)		Total
Assets	$	3,493		$	—	$	3,493
Liabilities	$	(2,965	)	$	—	$	(2,965	)

(1)	Represents counterparty netting under agreements governing such derivatives.

Derivatives listed above are recorded in “Current derivative asset or liability” and “Long-term derivative asset or liability” on the Company’s consolidated balance sheet and include swaps that are carried at fair value.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2019 (in thousands).


	Gross			Netting (1)		Total
Assets	$	4,176		$	—	$	4,176
Liabilities	$	(5,971	)	$	—	$	(5,971	)

(1)	Represents counterparty netting under agreements governing such derivatives.

The following table summarizes the effect of derivative contracts on the Consolidated Statements of Operations for the years ended December 31, 2020 and 2019 (in thousands):


	Year Ended December 31,
Contract Type	2020			2019
Crude oil contracts	$	18,561		$	1,614
Natural gas contracts		6,703			1,002

Realized gain	$	25,264		$	2,616

Crude oil contracts	$	8,120		$	(10,012	)
Natural gas contracts		(5,799	)		4,039

Unrealized gain (loss)	$	2,321		$	(5,973	)

Gain (loss) on derivatives, net	$	27,585		$	(3,357	)

In conjunction with the closing of the Mid-Con Acquisition in January 2021, the Company acquired the following additional derivative contracts via novation from Mid-Con:


Commodity	Period	Derivative	Volume/Month	Price/Unit
Oil	Jan 2021	Swap	20,883	Bbls	$	55.78	(1	)
Oil	Feb 2021	Swap	20,804	Bbls	$	55.78	(1	)
Oil	March 2021	Swap	20,725	Bbls	$	55.78	(1	)
Oil	April 2021	Swap	20,647	Bbls	$	55.78	(1	)
Oil	May 2021	Swap	20,563	Bbls	$	55.78	(1	)
Oil	June 2021	Swap	20,487	Bbls	$	55.78	(1	)
Oil	July 2021	Swap	20,412	Bbls	$	55.78	(1	)
Oil	Aug 2021	Swap	20,301	Bbls	$	55.78	(1	)
Oil	Sept 2021	Swap	20,228	Bbls	$	55.78	(1	)
Oil	Oct 2021	Swap	20,155	Bbls	$	55.78	(1	)
Oil	Nov 2021	Swap	20,084	Bbls	$	55.78	(1	)
Oil	Dec 2021	Swap	20,012	Bbls	$	55.78	(1	)
Oil	Jan 2021	Collar	20,883	Bbls	$	52.00-58.80	(1	)
Oil	Feb 2021	Collar	20,804	Bbls	$	52.00-58.80	(1	)
Oil	March 2021	Collar	20,725	Bbls	$	52.00-58.80	(1	)
Oil	April 2021	Collar	20,647	Bbls	$	52.00-58.80	(1	)
Oil	May 2021	Collar	20,563	Bbls	$	52.00-58.80	(1	)
Oil	June 2021	Collar	20,487	Bbls	$	52.00-58.80	(1	)
Oil	July 2021	Collar	20,412	Bbls	$	52.00-58.80	(1	)
Oil	Aug 2021	Collar	20,301	Bbls	$	52.00-58.80	(1	)
Oil	Sept 2021	Collar	20,228	Bbls	$	52.00-58.80	(1	)
Oil	Oct 2021	Collar	20,155	Bbls	$	52.00-58.80	(1	)
Oil	Nov 2021	Collar	20,084	Bbls	$	52.00-58.80	(1	)
Oil	Dec 2021	Collar	20,012	Bbls	$	52.00-58.80	(1	)

(1)	Based on West Texas Intermediate oil prices.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In the first quarter of 2021, the Company entered into the following additional derivative contracts:


Commodity	Period	Derivative	Volume/Month		Price/Unit
Oil	March 2021 - Oct 2021	Swap	25,000	Bbls	$	54.77	(1	)
Oil	Nov 2021 - Dec 2021	Swap	15,000	Bbls	$	54.77	(1	)
Oil	March 2021	Swap	50,000	Bbls	$	63.31	(1	)
Oil	April 2021	Swap	50,000	Bbls	$	63.13	(1	)
Oil	May 2021	Swap	50,000	Bbls	$	62.71	(1	)
Oil	June 2021	Swap	50,000	Bbls	$	62.17	(1	)
Oil	July 2021	Swap	50,000	Bbls	$	61.50	(1	)
Oil	Aug 2021	Swap	50,000	Bbls	$	60.94	(1	)
Oil	Sep 2021	Swap	50,000	Bbls	$	60.38	(1	)
Oil	Oct 2021	Swap	50,000	Bbls	$	59.89	(1	)
Oil	Nov 2021	Swap	50,000	Bbls	$	59.46	(1	)
Oil	Dec 2021	Swap	50,000	Bbls	$	59.01	(1	)
Oil	Jan 2022	Swap	60,000	Bbls	$	52.94	(1	)
Oil	Feb 2022	Swap	60,000	Bbls	$	52.65	(1	)
Oil	March 2022	Swap	60,000	Bbls	$	52.29	(1	)
Oil	April 2022	Swap	47,500	Bbls	$	51.98	(1	)
Oil	May 2022	Swap	45,000	Bbls	$	51.71	(1	)
Oil	June 2022	Swap	45,000	Bbls	$	51.41	(1	)
Oil	July 2022	Swap	45,000	Bbls	$	51.13	(1	)
Oil	Aug 2022	Swap	45,000	Bbls	$	50.89	(1	)
Oil	Sep 2022	Swap	45,000	Bbls	$	50.65	(1	)
Oil	Oct 2022	Swap	45,000	Bbls	$	50.45	(1	)
Oil	Nov 2022	Swap	55,000	Bbls	$	50.26	(1	)
Oil	Dec 2022	Swap	55,000	Bbls	$	50.22	(1	)
Oil	Jan 2023	Swap	57,500	Bbls	$	49.81	(1	)
Oil	Feb 2023	Swap	57,500	Bbls	$	49.63	(1	)
Oil	Jan 2022	Swap	60,000	Bbls	$	52.96	(1	)
Oil	Feb 2022	Swap	60,000	Bbls	$	52.66	(1	)
Oil	March 2022	Swap	60,000	Bbls	$	52.27	(1	)
Oil	April 2022	Swap	47,500	Bbls	$	51.96	(1	)
Oil	May 2022	Swap	45,000	Bbls	$	51.72	(1	)
Oil	June 2022	Swap	45,000	Bbls	$	51.42	(1	)
Oil	July 2022	Swap	45,000	Bbls	$	51.13	(1	)
Oil	Aug 2022	Swap	45,000	Bbls	$	50.90	(1	)
Oil	Sep 2022	Swap	45,000	Bbls	$	50.66	(1	)
Oil	Oct 2022	Swap	45,000	Bbls	$	50.47	(1	)
Oil	Nov 2022	Swap	55,000	Bbls	$	50.26	(1	)
Oil	Dec 2022	Swap	55,000	Bbls	$	50.01	(1	)
Oil	Jan 2023	Swap	57,500	Bbls	$	49.79	(1	)
Oil	Feb 2023	Swap	57,500	Bbls	$	49.62	(1	)
Natural Gas	March 2021	Swap	100,000	MMBtus	$	2.96	(2	)
Natural Gas	April 2021 - July 2021	Swap	350,000	MMBtus	$	2.96	(2	)
Natural Gas	Aug 2021 - Oct 2021	Swap	500,000	MMBtus	$	2.96	(2	)
Natural Gas	Nov 2021	Swap	450,000	MMBtus	$	2.96	(2	)
Natural Gas	April 2022	Swap	175,000	MMBtus	$	2.51	(2	)
Natural Gas	May 2022 - July 2022	Swap	150,000	MMBtus	$	2.51	(2	)
Natural Gas	Aug 2022 - Oct 2022	Swap	400,000	MMBtus	$	2.51	(2	)
Natural Gas	Nov 2022 - Feb 2023	Swap	750,000	MMBtus	$	2.72	(2	)

(1)	Based on West Texas Intermediate oil prices.

(2)	Based on Henry Hub NYMEX natural gas prices.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Stock Based Compensation

Effective January 1, 2014, the Company implemented performance-based long-term bonus plans under its compensation plan at the time (the “2009 Plan”) for the benefit of all employees through a Cash Incentive Bonus Plan (“CIBP”) and a Long-Term Incentive Plan (“LTIP”). The specific targeted performance measures under these sub-plans are approved by the Compensation Committee and/or the Company’s board of directors (the “Board”). Upon achieving the performance levels established each year, bonus awards under the CIBP and LTIP will be calculated as a percentage of base salary of each employee for the plan year. The CIBP and LTIP plan awards for each year are expected to be disbursed in the first quarter of the following year. Employees must be employed by the Company at the time that awards are disbursed to be eligible.

The CIBP awards will be paid in cash while LTIP awards will consist of restricted common stock, performance stock units and/or stock options. The number of shares of restricted common stock and the number of shares underlying the stock options granted will be determined based upon the fair market value of the common stock on the date of the grant.

Third Amended and Restated 2009 Incentive Compensation Plan

As of December 31, 2020, the Company had in place the Contango Oil & Gas Company Third Amended and Restated 2009 Incentive Compensation Plan (“the Third Amended 2009 Plan”) which allows for stock options, restricted stock or performance stock units to be awarded to officers, directors and employees as a performance-based award.

On March 21, 2017, the Board amended and restated the Company’s then existing incentive compensation plan through the adoption of the Second Amended 2009 Plan. The Second Amended 2009 Plan provides for both cash awards and equity awards to officers, directors, employees or consultants of the Company. On June 8, 2020 the Board amended and restated the Second Amended 2009 Plan through the adoption of the Third Amended 2009 Plan, which, among other things, increased the number of shares of the Company’s common stock authorized for issuance pursuant to the Third Amended 2009 Plan by 9,000,000 shares and increased the maximum aggregate number of shares of common stock that may be granted to any individual during any calendar year from 250,000 to 1,000,000. Awards made under the Third Amended 2009 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Board.

Under the terms of the Third Amended 2009 Plan, shares of the Company’s common stock may be issued for plan awards. Stock options under the Third Amended 2009 Plan must have an exercise price of each option equal to or greater than the market price of the Company’s common stock on the date of grant. The Company may grant officers and employees both incentive stock options intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended, and stock options that are not qualified as incentive stock options. Stock option grants to non-employees, such as directors and consultants, can only be stock options that are not qualified as incentive stock options. Options granted generally expire after five or ten years. The vesting schedule for all equity awards varies from immediately to over a three-year period. As of December 31, 2020, the Company had approximately 6.2 million shares of equity awards available for future grant under the Third Amended 2009 Plan, assuming performance stock units are settled at 100% of target.

2005 Stock Incentive Plan

The 2005 Plan was adopted by the Company’s Board in conjunction with the merger with Crimson Exploration, Inc. This plan expired on February 25, 2015, and therefore, no additional shares are available for grant.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Stock Options

A summary of stock options as of and for the years ended December 31, 2020 and 2019 is presented in the table below (dollars in thousands, except per share data):


	Year Ended December 31,
	2020					2019
	Shares Under Options			Weighted Average Exercise Price		Shares Under Options			Weighted Average Exercise Price
Outstanding, beginning of the period		20,964		$	58.53		33,637		$	55.82
Exercised		—		$	—		—		$	—
Expired / Forfeited		(1,117	)	$	39.00		(12,673	)	$	51.34

Outstanding, end of year		19,847		$	59.62		20,964		$	58.53

Aggregate intrinsic value	$	—				$	—
Exercisable, end of year		19,847		$	59.62		20,964		$	58.53
Aggregate intrinsic value	$	—				$	—
Available for grant, end of the period*		6,240,312					1,480,389
Weighted average fair value of options granted during the period	$	—				$	—

*	Assumes performance stock units are settled at 100% of target.

During the years ended December 31, 2020 and 2019, the Company did not issue any stock options. During the years ended December 31, 2020 and December 31, 2019, 1,117 and 12,673 stock options previously issued were forfeited by former employees, respectively.

As of December 31, 2020, there were 19,847 stock options vested and exercisable under the 2005 Plan. The exercise price for such options ranges from $28.96 to $60.33 per share, with an average remaining contractual life of 0.2 years.

Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the years ended December 31, 2020 and 2019, there was no excess tax benefit recognized. See Note 2 – “Summary of Significant Accounting Policies”.

Compensation expense related to employee stock option grants are recognized over the stock option’s vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model.

During the years ended December 31, 2020 and 2019, the Company did not recognize any stock option expense. The aggregate intrinsic value of stock options exercised/forfeited during each of the years ended December 31, 2020 and 2019 was zero.

Restricted Stock

During the year ended December 31, 2020, the Company issued 1,041,365 restricted stock awards to new and existing employees, which vest over three years, as part of their overall compensation package. During the year ended December 31, 2020, the Company issued 152,248 restricted stock awards to the members of the board of directors, which vest on the one-year anniversary of the date of grant, as well as an additional 50,914 restricted stock awards, in lieu of cash fees earned for the third quarter of 2020, which vested immediately. During the year ended December 31, 2020, 55,064 restricted stock awards were forfeited by former employees. The weighted average fair value of the restricted shares granted during the year was $2.22, with a total grant date fair value of approximately $2.8 million with no adjustment for an estimated weighted average forfeiture rate.

During the year ended December 31, 2019, the Company issued 307,650 restricted stock awards to new and existing employees, which vest over three years, plus an additional 80,410 restricted stock awards to the members of the board of directors, which vest on the one-year anniversary of the date of grant, as part of their overall compensation package. During the year ended December 31, 2019, 91,346 restricted stock awards were forfeited by former employees. The weighted average fair value of the restricted shares granted during the year was $2.91, with a total grant date fair value of approximately $1.1 million with no adjustment for an estimated weighted average forfeiture rate.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Restricted stock activity as of December 31, 2020 and 2019 and for the years then ended is presented in the table below (dollars in thousands, except per share data):


	2020							2019
	Restricted Shares			Weighted Average Fair Value		Aggregate Intrinsic Value		Restricted Shares			Weighted Average Fair Value		Aggregate Intrinsic Value
Outstanding, beginning of the period		403,221		$	3.66	$	214		459,621		$	7.26	$	662
Granted		1,244,527			2.22		65		388,060			2.91		—
Vested		(289,636	)		3.48		700		(353,114	)		7.41		1,171
Canceled / Forfeited		(55,064	)		2.45		16		(91,346	)		4.08		41

Not vested, end of the period		1,303,048			2.38		228		403,221			3.66		214

The Company recognized approximately $1.3 million and $1.9 million in restricted stock compensation expense during the years ended December 31, 2020 and 2019, respectively, for restricted shares granted to its officers, employees and directors. The lower 2020 expense is primarily related to the issuance of stock in the third quarter of 2020 as compared to stock issued in the first quarter of 2019. As of December 31, 2020, there were 1,303,048 shares of unvested restricted stock outstanding, and an additional $2.3 million of compensation expense related to restricted stock remains to be recognized over the remaining vesting period of 2.1 years.

Performance Stock Units

Performance stock units (“PSUs”) represent the opportunity to receive shares of the Company’s common stock at the time of settlement. The number of shares to be awarded upon settlement of the PSUs may range from 0% to 300% of the targeted number of PSUs stated in the award agreements, contingent upon the achievement of certain share price appreciation targets compared to share appreciation of a specific peer group or peer group index over a three-year period. The PSUs vest at the end of the three-year performance period, with the final number of shares to be issued determined at that time, based on the Company’s share performance during the period compared to the average performance of the peer group.

Compensation expense associated with PSUs is based on the grant date fair value of a single PSU as determined using the Monte Carlo simulation model, which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee intends to settle the PSUs with shares of the Company’s common stock after three years, the PSU awards are accounted for as equity awards, and the fair value is calculated on the grant date. The simulation model calculates the payout percentage based on the stock price performance over the performance period. The concluded fair value is based on the average achievement percentage over all the iterations. The resulting fair value expense is amortized over the life of the PSU award.

During the year ended December 31, 2020, the Company granted 2,846,140 PSUs to executive officers and certain employees as part of their overall compensation package. The performance period will be measured between May 1, 2020 and April 30, 2023. These granted PSUs were valued at a weighted average fair value of $4.90 per unit. All fair value prices were determined using the Monte Carlo simulation model. In January 2020, 77,485 shares of the PSUs granted in 2017 vested, of which 22,972 PSUs were withheld for taxes, and are included with the restricted stock activity in the consolidated statement of shareholders’ equity. In December 2020, 68,476 shares of the PSUs granted in 2018 vested, of which 18,284 PSUs were withheld for taxes and are included with the restricted stock activity in the consolidated statement of shareholders’ equity. No PSUs were forfeited during the year ended December 31, 2020. The Company recognized approximately $3.0 million in stock compensation expense related to PSUs during 2020. As of December 31, 2020, an additional $11.7 million of compensation expense related to PSUs remained to be recognized over the remaining vesting period of 2.3 years.

During the year ended December 31, 2019, the Company granted 117,105 PSUs to executive officers and employees as part of their overall compensation package, which will be measured between January 1, 2019 and December 31, 2021, and were valued at a weighted average fair value of $6.42 per unit. All fair value prices were

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

determined using the Monte Carlo simulation model. During the year ended December 31, 2019, 71,945 PSUs were forfeited by former employees, including 49,773 PSU forfeitures due to the resignations of the Company’s former Senior Vice President of Exploration and Senior Vice President of Operations and Engineering in February 2019. The Company only recognized approximately $0.5 million in stock compensation expense related to PSUs during 2019, primarily due to the expiration of PSUs which failed to meet their target as of December 31, 2018 and the above referenced forfeitures.

8. Share Repurchase Program

In September 2011, the Company’s board of directors approved a $50 million share repurchase program. All shares are to be purchased in the open market or through privately negotiated transactions. Purchases are made subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market, and when the Company believes its stock price to be undervalued. Repurchased shares of common stock become authorized but unissued shares and may be issued in the future for general corporate and other purposes. No shares were purchased during the years ended December 31, 2020 and 2019. As of December 31, 2020, the Company had $31.8 million available under the share repurchase program for future purchases; however, repurchases could be limited by provisions of the Company’s Credit Agreement.

9. Leases

As of January 1, 2019, the Company adopted Accounting Standards Codification Topic 842 – Leases (“ASC 842”), which requires lessees to recognize a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis, and a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term on the Company’s consolidated balance sheet.

During the year ended December 31, 2020, the Company entered into new compressor contracts with lease terms of twelve months or more, which qualify as operating leases. The Company also entered into new contracts for vehicles and office equipment with lease terms of twelve months or more, which qualify as finance leases. As of December 31, 2020, the Company’s operating leases were for compressors and office space for two corporate offices and three field offices, while the Company’s finance leases were for vehicles and office equipment. These leases do not have a material net impact on the Company’s consolidated financial statements.

The following table summarizes the balance sheet information related to the Company’s leases as of December 31, 2020 and December 31, 2019 (in thousands):


	December 31, 2020			December 31, 2019
Operating lease right of use asset (1)	$	2,452		$	4,316
Operating lease liability - current (2)	$	(1,832	)	$	(2,597	)
Operating lease liability - long-term (3)		(522	)		(1,738	)

Total operating lease liability	$	(2,354	)	$	(4,335	)

Financing lease right of use asset (1)	$	2,996		$	1,569
Financing lease liability - current (2)	$	(940	)	$	(524	)
Financing lease liability - long-term (3)		(2,102	)		(1,051	)

Total financing lease liability	$	(3,042	)	$	(1,575	)

(1)	Included in “Right-of-use lease assets” on the consolidated balance sheet.

(2)	Included in “Accounts payable and accrued liabilities” on the consolidated balance sheet.

(3)	Included in “Lease liabilities” on the consolidated balance sheet.

The Company’s leases generally do not provide an implicit rate, and therefore the Company uses its incremental borrowing rate as the discount rate when measuring operating lease liabilities. The incremental borrowing rate represents an estimate of the interest rate the Company would incur at lease commencement to borrow an amount equal to the lease payments on a collateralized basis over the term of a lease. For operating leases existing prior to January 1, 2019, the incremental borrowing rate as of January 1, 2019 was used for the remaining lease term.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The table below presents the weighted average remaining lease terms and weighted average discount rates for the Company’s leases as of December 31, 2020 and December 31, 2019:


	December 31, 2020			December 31, 2019
Weighted Average Remaining Lease Terms (in years):
Operating leases		1.47			2.16
Financing leases		3.24			3.14
Weighted Average Discount Rate:
Operating leases		5.72	%		6.04	%
Financing leases		5.92	%		6.24	%

Maturities for the Company’s lease liabilities on the consolidated balance sheet as of December 31, 2020, were as follows (in thousands):


	December 31, 2020
	Operating Leases			Financing Leases
2021	$	1,906		$	1,094
2022		240			980
2023		170			823
2024		158			459

Total future minimum lease payments		2,474			3,356
Less: imputed interest		(120	)		(314	)

Present value of lease liabilities	$	2,354		$	3,042

The following table summarizes expenses related to the Company’s leases for the three months ended December 31, 2020 and December 31, 2019 (in thousands):


	Three Months Ended December 31, 2020		Three Months Ended December 31, 2019
Operating lease cost (1) (2)	$	843	$	542
Financing lease cost - amortization of right-of-use assets		231		87
Financing lease cost - interest on lease liabilities		47		17
Administrative lease cost (3)		19		19
Short-term lease cost (1) (4)		360		741

Total lease cost	$	1,500	$	1,406

(1)	This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners.

(2)	Costs related to office leases and compressors with lease terms of twelve months of more.

(3)	Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year.

(4)	Costs related primarily to drilling rigs, generators and compressor agreements with lease terms of more than one month and less than one year.

The following table summarizes expenses related to the Company’s leases for the years ended December 31, 2020 and December 31, 2019 (in thousands):


	Year Ended December 31, 2020		Year Ended December 31, 2019
Operating lease cost (1) (2)	$	3,055	$	742
Financing lease cost - amortization of right-of-use assets		642		92
Financing lease cost - interest on lease liabilities		131		18
Administrative lease cost (3)		75		75
Short-term lease cost (1) (4)		1,974		4,101

Total lease cost	$	5,877	$	5,028

(1)	This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(2)	Costs related to office leases and compressors with lease terms of twelve months of more. Higher costs in 2020 due to additional leases related to the properties acquired from Will Energy and White Star during the three months ended December 31, 2019.

(3)	Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year.

(4)	Costs related primarily to drilling rigs, generators and compressor agreements with lease terms of more than one month and less than one year.

There were $3.2 million and $0.9 million in cash payments related to operating leases and financing leases, respectively, during the year ended December 31, 2020. There were $0.8 million and $0.1 million in cash payments related to operating leases and financing leases, respectively, during the year ended December 31, 2019.

10. Other Financial Information

The following table provides additional detail for accounts receivable, prepaids and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands):


	December 31, 2020			December 31, 2019
Accounts receivable:
Trade receivables	$	20,306		$	21,110
Receivable for Alta Resources distribution		1,712			1,712
Joint interest billings		15,637			13,104
Income taxes receivable		268			509
Other receivables		2,209			4,126
Allowance for doubtful accounts (1)		(2,270	)		(994	)

Total accounts receivable	$	37,862		$	39,567

Prepaid Expenses:
Prepaid insurance	$	2,825		$	683
Other (2)		535			508

Total Prepaid Expenses	$	3,360		$	1,191

Accounts payable and accrued liabilities:
Royalties and revenue payable	$	23,701		$	15,905
Legal suspense related to revenues (3)		27,983			33,739
Advances from partners (4)		76			6,733
Accrued exploration and development (4)		490			8,210
Trade payables		14,273			14,086
Accrued general and administrative expenses (5)		6,191			12,037
Accrued operating expenses		5,755			5,794
Accrued operating and finance leases		2,772			3,120
Other accounts payable and accrued liabilities		2,729			4,969

Total accounts payable and accrued liabilities	$	83,970		$	104,593

(1)	Increase in 2020 primarily due to the additional properties acquired from Will Energy and White Star.

(2)	Other prepaids primarily includes software licenses.

(3)	Suspended revenues primarily relate to amounts for which there is some question as to valid ownership, unknown addresses of payees or some other payment dispute.

(4)	Decrease in 2020 due to a decrease in drilling and completion activity. In response to the dramatic decline in commodity prices in the first quarter of 2020, the Company suspended further operated drilling in its West Texas area, and in its other onshore areas.

(5)	The December 31, 2019 balance includes an accrual of $6.3 million for a legal judgment that was paid in April 2020. See Note 14 – “Commitment and Contingencies” for further information.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Included in the table below is supplemental cash flow disclosures and non-cash investing activities during the years ended December 31, 2020 and 2019, in thousands:


	Year Ended December 31,
	2020			2019
Cash payments:
Interest payments	$	3,592		$	7,761
Income tax payments, net of cash refunds		293			668
Non-cash items excluded from investing activities in the consolidated statements of cash flows:
Increase (decrease) in accrued capital expenditures		(7,615	)		1,841

11. Investment in Exaro Energy III LLC

Through the Company’s wholly-owned subsidiary, Contaro Company (“Contaro”), the Company committed to invest up to $67.5 million in Exaro for an ownership interest of approximately 37%. The aggregate commitment of all the Exaro investors was approximately $183 million. The Company did not make any contributions during the year ended December 31, 2020 and has no plans to invest additional funds in Exaro, as the commitment to invest in Exaro expired on March 31, 2017. As of December 31, 2020, the Company had invested approximately $46.9 million. Contango’s share in the equity of Exaro at December 31, 2020 was approximately $6.8 million.

The Company’s share in Exaro’s results of operations recognized for the years ended December 31, 2020 and 2019 was a gain of approximately $27,000, net of zero tax expense and a gain of approximately $1.0 million, net of zero tax, respectively.

12. Asset Retirement Obligation

The Company accounts for its retirement obligation of long lived assets by recording the net present value of a liability for an ARO in the period in which it is incurred. When the liability is initially recorded, the Company increases the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement.

Activities related to the Company’s ARO during the years ended December 31, 2020 and 2019 were as follows (in thousands):


	Year Ended December 31,
	2020			2019
Balance as of the beginning of the period	$	51,665		$	13,497
Liabilities incurred during period		5			256
Liabilities settled during period		(338	)		(1,380	)
Accretion		2,702			1,062
Sales		(5,239	)		(816	)
Acquisitions		—			37,596
Change in estimate		3,978			1,450

Balance as of the end of the period	$	52,773		$	51,665

All of the total liabilities incurred during the years ended December 31, 2020 and 2019 were related to new wells drilled during the period. All of the total liabilities settled during the years ended December 31, 2020 and 2019 were related to wells plugged and abandoned during the period. The acquisitions refer to new liabilities assumed from the properties acquired in 2019 from White Star and Will Energy. The change in estimate relates to year-end adjustments for updated estimated plugging and abandonment costs, primarily in the Company’s Central Oklahoma and Western Anadarko regions.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. Long-Term Debt

Credit Agreement

On September 17, 2019, the Company entered into its new revolving Credit Agreement with JPMorgan Chase Bank, N.A. and other lenders, which established a borrowing base of $65 million.

The borrowing base is subject to semi-annual redeterminations which will occur on or around May 1st and November 1st of each year. The Credit Agreement was amended on November 1, 2019, in conjunction with the closing of the Will Energy Acquisition and White Star Acquisition, to add two additional lenders and increase the borrowing base thereunder to $145 million. On June 9, 2020, the Company entered into the Second Amendment to the Credit Agreement (the “Second Amendment”). The Second Amendment redetermined the borrowing base at $95 million, among other things, pursuant to the regularly scheduled redetermination process. The Second Amendment also provided for further $10 million automatic reductions in the borrowing base on each of June 30, 2020 and September 30, 2020. On October 30, 2020, the Company entered into the Third Amendment to the Credit Agreement, which became effective on January 21, 2021, upon the satisfaction of certain conditions, including the consummation of the Mid-Con Acquisition. See Note 4 – “Acquisitions and Dispositions” for more information. The Third Amendment provided for, among other things, (i) a 25 basis point increase in the applicable margin at each level of the borrowing base utilization-based pricing grid, (ii) an increase of the borrowing base to $130.0 million on the effective date of the Third Amendment with a $10.0 million automatic stepdown in the borrowing base on March 31, 2021, (iii) certain modifications to the Company’s minimum hedging covenant including requiring hedging for at least 75% of the Company’s projected PDP volumes for 24 full calendar months on or prior to 30 days after the effective date of the Third Amendment and on April 1 and October 1 of each calendar year, (iv) addition of three new lenders to the lender group. As of December 31, 2020, the borrowing base was $75 million. In connection with the closing of the Mid-Con Acquisition on January 21, 2021, the borrowing base increased automatically to $130.0 million. The next regularly scheduled borrowing base redetermination is on or before May 1, 2021.

Initially, the Company incurred $1.8 million of arrangement and upfront fees in connection with the Credit Agreement and incurred an additional $1.6 million in fees for the first amendment to the Credit Agreement, all to be amortized over the remaining term of the Credit Agreement. No fees were incurred for the Second Amendment; however, during the three months ended June 30, 2020, the Company expensed $1.0 million of the debt issuance costs discussed above, which originally were to be amortized over the life of the loan, due to the reduction in the borrowing base per the Second Amendment. The Company initially incurred $0.1 million in fees related to the Third Amendment during the three months ended December 31, 2020. During the year ended December 31, 2020, the Company amortized debt issuance costs of $1.6 million related to the Credit Agreement, including the $1.0 million mentioned above. As of December 31, 2020, the remaining balance of these fees was $1.8 million, which will be amortized through September 17, 2024. In January 2021, the Company incurred an additional $0.9 million in fees related to the Third Amendment that became effective on January 21, 2021, in connection with the closing of the Mid-Con Acquisition. These fees will also be amortized over the remaining term of the loan.

As of December 31, 2020, the Company had $9.0 million outstanding under the Credit Agreement and $1.9 million in outstanding letters of credit. As of December 31, 2019, the Company had $72.8 million outstanding under the Credit Agreement and $1.9 million in outstanding letters of credit. As of December 31, 2020, borrowing availability under the Credit Agreement was $64.1 million.

The Credit Agreement is collateralized by liens on substantially all of the Company’s oil and natural gas properties and other assets and security interests in the stock of its wholly owned and/or controlled subsidiaries. The Company’s wholly owned and/or controlled subsidiaries are also required to join as guarantors under the Credit Agreement.

Borrowings under the Credit Agreement bear interest at LIBOR, the U.S. prime rate, or the federal funds rate, plus a 1.75% to 3.75% margin, dependent upon the amount outstanding. Total interest expense under the Company’s Credit Agreement, including commitment fees, the additional $1.0 million in expensed loan fees discussed above and other financing fees was approximately $5.0 million for the year ended December 31, 2020. Total interest expense under the Company’s current and previous credit agreements, including commitment fees and other financing fees, was approximately $8.6 million for the year ended December 31, 2019.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The weighted average interest rates in effect at December 31, 2020 and December 31, 2019 were 2.9% and 4.3% under the Credit Agreement, respectively.

The Credit Agreement contains customary and typical restrictive covenants. The Credit Agreement requires a Current Ratio of greater than or equal to 1.0 and a Leverage Ratio of less than or equal to 3.50, both as defined in the Credit Agreement. The Second Amendment includes a waiver of the Current Ratio requirement until the quarter ending March 31, 2022. Additionally, the Second Amendment, among other things, provides for an increase in the Applicable Margin grid on borrowings outstanding of 50 basis points, and includes provisions requiring monthly aged accounts payable reports and typical anti-cash hoarding and cash sweep provisions with respect to a consolidated cash balance in excess of $5.0 million. The Credit Agreement also contains events of default that may accelerate repayment of any borrowings and/or termination of the facility. Events of default include, but are not limited to, a going concern qualification, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events. As of December 31, 2020, the Company was in compliance with all of its covenants under the Credit Agreement.

Paycheck Protection Program Loan

On April 10, 2020, the Company entered into a promissory note evidencing an unsecured loan in the amount of approximately $3.4 million (the “PPP Loan”) made to the Company under the Paycheck Protection Program (the “PPP”). The PPP was established under the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”), signed into law on March 27, 2020, and is administered by the U.S. Small Business Administration. The PPP Loan to the Company is being made through JPMorgan Chase Bank, N.A and is included in “Long-Term Debt” on the Company’s consolidated balance sheet.

The PPP Loan matures on the two-year anniversary of the funding date and bears interest at a fixed rate of 1.00% per annum. Monthly principal and interest payments, less the amount of any potential forgiveness (discussed below), will commence after the six-month anniversary of the funding date. The promissory note evidencing the PPP Loan provides for customary events of default, including, among others, those relating to failure to make payment, bankruptcy, breaches of representations and material adverse effects. The Company may prepay the principal of the PPP Loan at any time without incurring any prepayment charges.

Under the terms of the CARES Act, PPP loan recipients can apply for and be granted forgiveness for all or a portion of the loans granted under the PPP, subject to an audit. Under the CARES Act, loan forgiveness is available, subject to limitations, for the sum of documented payroll costs, covered mortgage interest payments, covered rent payments and covered utilities during either: (1) the eight-week period beginning on the funding date; or (2) the 24-week period beginning on the funding date. Forgiveness is reduced if full-time employee headcount declines, or if salaries and wages for employees with salaries of $100,000 or less annually are reduced by more than 25%. The Company utilized the PPP Loan amount for qualifying expenses during the 24-week coverage period, and on September 30, 2020, submitted its application for forgiveness of all of the PPP Loan in accordance with the terms of the CARES Act and related guidance. The Company is currently awaiting a response from the Small Business Administration. In the event the PPP Loan or any portion thereof is forgiven, the amount forgiven is applied to the outstanding principal.

14. Commitments and Contingencies

Contango leases its office space, compressors, vehicles and certain other equipment, which are considered operating and finance leases. See Note 9 – “Leases” for more information. The Company also incurs commitments on its oil and natural gas leases, such as delay rentals, surface damage payments and rental payments associated with salt water disposal contracts.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As of December 31, 2020, minimum future operating and finance lease payments and other commitments listed above for Contango’s fiscal years are as follows (in thousands):


Fiscal years ending December 31,
2021	$	3,941
2022		2,163
2023		1,872
2024		1,496
2025 and thereafter		879

Total	$	10,351

The amounts incurred under operating and finance leases and payments related to delay rentals, surface use and salt water disposal contracts during the years ended December 31, 2020 and 2019 were approximately $4.3 million and $1.5 million, respectively. The increase in 2020 payments is due to the properties acquired in the Will Energy Acquisition and the White Star Acquisition.

Throughput Contract Commitment

The Company had a signed a throughput agreement with a third-party pipeline owner/operator that constructed a natural gas gathering pipeline in Southeast Texas that allowed the Company to defray the cost of building the pipeline itself. Beginning in late 2016, the Company was unable to meet the minimum monthly gas volume deliveries through this line in Southeast Texas and continued to not meet the minimum throughput requirements under the agreement through the expiration of the throughput commitment on March 31, 2020. As of December 31, 2019, the Company recorded a $1.0 million loss contingency through the end of the contract in March 2020, which was paid in three equal monthly installments in 2020. As the remaining throughput commitment fees of $1.0 million were accrued during the year ended December 31, 2019, the Company incurred no expense related to this commitment in 2020.

Legal Proceedings

From time to time, the Company is involved in legal proceedings relating to claims associated with its properties, operations or business or arising from disputes with vendors in the normal course of business, including the material matters discussed below.

On November 16, 2010, a subsidiary of the Company, several predecessor operators and several product purchasers were named in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interest in two wells that has not been recognized by the Company or by predecessor operators to which the Company had granted indemnification rights. In dispute is whether ownership rights were transferred through a number of decades-old poorly documented transactions. Based on prior summary judgments, the trial court entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus post-judgment interest. The Company appealed the trial court’s decision to the applicable state Court of Appeals, and in the fourth quarter of 2017, the Court of Appeals issued its opinion and affirmed the trial court’s summary decision. In the first quarter of 2018, the Company filed a motion for rehearing with the Court of Appeals, which was denied, as expected. The Company filed a petition requesting a review by the Texas Supreme Court, as the Company believes the trial and appellate courts erred in the interpretation of the law. In early October 2019, the Texas Supreme Court notified the Company that it would not hear this case. The Company engaged additional legal representation to assist in the preparation of an amended petition requesting that the Texas Supreme Court reconsider its initial decision to not review the case. That amended petition was filed, and in mid-March 2020, the Texas Supreme Court decided they would not re-hear the case. Consequently, during the three months ended December 31, 2019, the Company recorded a $6.3 million liability for the judgment, interest and fees, with $3.5 million of such liability related to suspended funds reflected in “Accounts payable and accrued liabilities” on the Company’s consolidated balance sheet for the year ended December 31, 2019. The judgment, interest and fees were paid in April 2020.

On January 14, 2016, the Company was named as the defendant in a lawsuit filed in the District Court for Harris County in Texas by a third-party operator. The Company participated in the drilling of a well in 2012, which experienced serious difficulties during the initial drilling, which eventually led to the plugging and abandoning of the wellbore prior to reaching the target depth. In dispute is whether the Company is responsible for the additional

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

costs related to the drilling difficulties and plugging and abandonment. In September 2019, the case went to trial, and, in October 2019, the court ruled in favor of the plaintiff. Prior to the judgment, the Company had approximately $1.1 million in accounts payable related to the disputed costs associated with this case. As a result of the judgment, during the three months ended September 30, 2019, the Company recorded an additional $2.1 million liability for the final judgment plus fees and interest. The Company also prepared and filed an appeal with the appellate court for a review of the initial trial court decision The plaintiff petitioned the appellate court for an extension of time to file briefs with the court until late in the fourth quarter of 2020. On January 23, 2021, the appellate court notified both parties that it would begin reviewing the merits of the case beginning on February 23, 2021. On March 3, 2021, the appellate court affirmed the trial court’s decision. The Company plans to appeal the decision to the Supreme Court.

While many of these matters involve inherent uncertainty and the Company is unable at the date of this filing to estimate an amount of possible loss with respect to certain of these matters, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings or claims will not have a material adverse effect on its consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company maintains various insurance policies that may provide coverage when certain types of legal proceedings are determined adversely.

15. Net Loss Per Common Share

A reconciliation of the components of basic and diluted net loss per common share for the years ended December 31, 2020 and 2019 is presented below (in thousands):


	Year Ended December 31, 2020
	Net Loss			Shares		Per Share
Basic Earnings per Share:
Net loss attributable to common stock	$	(165,342	)		137,522	$	(1.20	)

Diluted Earnings per Share:
Effect of potential dilutive securities:
Weighted average of incremental shares (stock options, restricted stock and PSUs)		—			—		—

Net loss attributable to common stock	$	(165,342	)		137,522	$	(1.20	)


	Year Ended December 31, 2019
	Net Loss			Shares		Per Share
Basic Earnings per Share:
Net loss attributable to common stock	$	(159,796	)		54,136	$	(2.95	)

Diluted Earnings per Share:
Effect of potential dilutive securities:
Weighted average of incremental shares (stock options, restricted stock and PSUs)		—			—		—

Net loss attributable to common stock	$	(159,796	)		54,136	$	(2.95	)

The numerator for basic earnings per share is net loss attributable to common stockholders. The numerator for diluted earnings per share is net loss available to common stockholders.

Potential dilutive securities (stock options, restricted stock and PSUs) have not been considered when their effect would be antidilutive. The potentially dilutive shares would have been 529,508 shares and 613,506 shares for the years ended December 31, 2020 and 2019, respectively.

16. Income Taxes

Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income taxes are measured by applying currently enacted tax rates to the differences between financial statements and income tax reporting. Numerous judgments and

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

assumptions are inherent in the determination of deferred income tax assets and liabilities as well as income taxes payable in the current period. The Company is subject to taxation in several jurisdictions, and the calculation of its tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in various taxing jurisdictions.

Income Tax Computation

Actual income tax expense differs from income tax expense computed by applying the U.S. federal statutory corporate rate of 21 percent for the years ended December 31, 2020 and 2019, respectively, to pretax income as follows (dollars in thousands):


	Year Ended December 31,
	2020					2019
Benefit at statutory tax rate	$	(34,663	)	21.00	%	$	(33,561	)	21.00	%
State income tax provision, net of federal benefit		467		(0.28	)%		555		(0.35	)%
State deferred tax benefit		(5,553	)	3.36	%		—		—	%
Permanent differences		26		(0.02	)%		30		(0.02	)%
Stock based compensation		81		(0.05	)%		979		(0.61	)%
Valuation allowance		40,059		(24.27	)%		34,239		(21.42	)%
Other		330		(0.20	)%		(2,022	)	1.26	%

Income tax provision	$	747		(0.46	)%	$	220		(0.14	)%

The effective tax rate for the years ended December 31, 2020 and 2019 varies from the statutory rate primarily as a result of recording a valuation allowance.

The provision (benefit) for income taxes for the periods indicated are comprised of the following (in thousands):


	Year Ended December 31,
	2020		2019
Current tax provision (benefit):
Federal	$	275	$	(335	)
State		472		555

Total	$	747	$	220

Deferred tax benefit:
Federal	$	—	$	—
State		—		—

Total	$	—	$	—

Total tax provision (benefit):
Federal	$	275	$	(335	)
State		472		555

Total	$	747	$	220

Included in gain from investment in affiliates	$	—	$	—

Total income tax provision	$	747	$	220

The Federal income tax expense results from an adjustment in the previous period of the credit for Alternative Minimum Tax (“AMT”) paid in prior years. As a result of the tax reform in 2017, the corporate AMT was repealed, and any AMT credit was made refundable. The first half of the credit was refunded when the Company filed its 2018 federal income tax return, and the second half of the credit was refunded when the Company filed its 2019 federal tax return. The CARES Act modified the timing of these refunds, allowing the Company to request an expedited refund of $0.3 million during the quarter ended June 30, 2020. This amount was previously accounted for as an income tax benefit when the corporate AMT was repealed. State income tax expense relates to income taxes for the quarter and the nine months which are expected to be owed to the states of Louisiana and Oklahoma resulting from activities within those states and, in each case, that are not shielded by existing Federal tax attributes.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Additionally, under the CARES Act, the Company will benefit from an amendment to Internal Revenue Code Section 163(j) that temporarily increases deductible interest expense limitations. Specifically, the CARES Act increases the 30% Adjusted Taxable Income (“ATI”) limitation to 50% of ATI for taxable years beginning in each of 2019 and 2020. This will have the effect of allowing the Company to use a Section 163(j) carryover from the prior year that was not limited by Section 382 (discussed below). The Company does not expect to benefit from any other income tax-related provisions of the CARES Act.

The net deferred tax is comprised of the following (in thousands):


	December 31,
	2020			2019
Deferred tax assets:
Net operating loss carryforward	$	84,982		$	80,617
Deferred compensation		447			—
Derivative instruments		—			377
State deferred tax assets		6,507			954
Oil and gas properties		39,081			11,436
Investment in affiliates		752			2,799
Recognized built in loss carryforward		9,987			6,718
163(j) Carryforward		1,828			1,585
Other		1,796			964

Total deferred tax assets before valuation allowance	$	145,380		$	105,450
Valuation allowance		(145,269	)		(105,212	)

Net deferred tax assets	$	111		$	238

Deferred tax liability:
Deferred compensation	$	—		$	(238	)
Derivative instruments		(111	)		—

Deferred tax liability	$	(111	)	$	(238	)

Total net deferred tax	$	—		$	—

Accounting for uncertainty in income taxes prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities.

In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Based upon the amount of deferred tax liabilities, level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, the Company believes it is not more-likely-than-not that it will realize the benefits of these deductible differences and has recorded a valuation allowance for federal and state purposes of approximately $138.8 million and approximately $6.5 million, respectively.

As of December 31, 2020, the Company had federal net operating loss (“NOL”) carryforwards of approximately $404.7 million and state NOLs of $26.4 million. The Federal NOL carryforwards are made up of: (i) those acquired in the merger with Crimson Exploration, Inc. (“Crimson”) in 2013 (the “Merger”) and (ii) from subsequent taxable losses during the years 2014 through 2020 due to lower commodity prices and utilization of various elections available to the Company in expensing capital expenditures incurred in the development of oil and natural gas properties. Generally, these NOLs are available to reduce future taxable income and the related income tax liability subject to the limitations set forth in Internal Revenue Code Section 382 related to changes of more than 50% of ownership of the Company’s stock by 5% or greater shareholders over a three-year period (a Section 382 Ownership Change) from the time of such an ownership change. Recently passed legislation, however, temporarily suspends the Section 172 limitation for NOLs arising in a tax year beginning in 2018, 2019 or 2020 and also allows these NOLs to be carried back five years.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

On November 19, 2018, the Company completed a follow-on offering (the “2018 Offering”) of 7.5 million additional shares of common stock. Prior to December 18, 2018, the underwriters exercised their Green Shoe option purchasing an additional approximate 1.1 million shares, resulting in a total of approximately 8.6 million primary shares issued in the Offering. This issuance resulted in a Section 382 Ownership Change (the “2018 Ownership Change”) which limits the Company’s future ability to use its NOLs. As such, the Company is limited in use of NOLs for amounts incurred prior to November 20, 2018 in an amount estimated to be approximately $2.4 million per year (plus any recognized built in gains during the next five years) or until expiration of each annual vintage of NOL (generally, 20 years for each annual vintage of NOLs incurred prior to 2018).

On September 12, 2019, as discussed in Note 1 – “Organization and Business”, the Company completed the September 2019 Public Offering which also resulted in a Section 382 Ownership Change on that date (the “2019 Ownership Change” and, together with the 2018 Ownership Change, the “Ownership Changes”). Due to changing market conditions, the Company’s ability to utilize pre-2018 NOLs on that date could be limited to $700,000 a year (in pre-tax dollars). This lower annual limitation resulting from the 2019 Ownership Change effectively eliminates the ability to utilize these tax attributes in the future.

The Company is also affected by the limitation in Section 163(j) on interest taken in any given tax year. As of December 31, 2020, the Company had a limitation of $2.4 million which will carry over indefinitely. Additionally, the Company’s post-2017 NOLs of $132.7 million are also not subject to expiration, but are limited to offsetting 80% of the Company’s taxable income in any year of usage after December 31, 2020. These carryovers are subject to any applicable Section 382 limitation (discussed above).

As a result of the Ownership Changes, the Company has recorded a valuation allowance against substantially all of its NOLs and other deferred tax assets. The valuation allowance balance at December 31, 2020 is $145.3 million.

ASC 740, Income Taxes (“ASC 740”) prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. As a result of the Merger, the Company acquired certain tax positions taken by Crimson in prior years. These positions are not expected to have a material impact on results of operations, financial position or cash flows. A reconciliation of the beginning and ending amount of unrecognized income tax benefits is as follows (in thousands):


	Unrecognized Tax Benefits
Balance at December 31, 2019	$	—
Additions based on tax positions related to the current year		—
Additions based on tax positions related to prior years		—
Additions due to acquisitions		—
Reductions due to a lapse of the applicable statute of limitations		—
Change in rate due to remeasurement		—

Balance at December 31, 2020	$	—

The Company’s policy is to recognize interest and penalties related to uncertain tax positions as income tax benefit (expense) in the Company’s consolidated statements of operations. The Company had no interest or penalties related to unrecognized tax benefits for the year ended December 31, 2020 or any prior years. The total amount of unrecognized tax benefit, if recognized, that would affect the effective tax rate was zero.

Generally, the Company’s income tax years of 2009 through 2020 remain open and subject to examination by Federal tax authorities, and the tax years of 2009 through 2020 remain open and subject to examination by the tax authorities in Texas, Louisiana and Oklahoma, which are the jurisdictions where the Company carries its principal operations. These audits can result in adjustments of taxes due or adjustments of the NOL carryforwards that are available to offset future taxable income. The Company currently has no ongoing tax audits and has not been

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

notified of pending activity by taxing jurisdictions. The Company does not anticipate that the total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of the statute of limitations prior to December 31, 2020.

17. Subsequent Events

Mid-Con Acquisition

On January 21, 2021, the Company closed the Mid-Con Acquisition in an all-stock merger transaction. At the time of close, each common unit representing limited partner interests in Mid-Con issued and outstanding (other than treasury units or units held by Mid-Con GP) was converted automatically into the right to receive 1.75 shares of the Company’s common stock. A total of 25,409,164 shares of Contango common stock were issued at the closing of the Mid-Con Acquisition. See Note 4 – “Acquisitions and Dispositions” for more information.

Silvertip Acquisition

On February 1, 2021, the Company closed the Silvertip Acquisition to acquire certain oil and natural gas properties located in the Big Horn Basin in Wyoming and Montana, in the Powder River Basin in Wyoming and in the Permian Basin in Texas and New Mexico, for aggregate consideration of approximately $58 million in cash. The Company previously paid a $7.0 million deposit during the three months ended December 31, 2020, in connection with the execution of the purchase agreement, and a balance of $46.2 million was paid upon closing of the Silvertip Acquisition, after customary closing adjustments, including the results of operations during the period between the effective date of August 1, 2020 and the closing date. See Note 4 – “Acquisitions and Dispositions” for more information.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS DISCLOSURE (Unaudited)

In accordance with U.S. GAAP for disclosures regarding oil and natural gas producing activities, and SEC rules for oil and natural gas reporting disclosures, we are making the following disclosures regarding our oil and natural gas reserves and exploration and production activities.

Capitalized Costs Related to Oil and Natural Gas Producing Activities

The following table presents information regarding our net capitalized costs related to oil and natural gas producing activities as of the date indicated (in thousands):


	December 31,
	2020			2019
Proved oil and gas properties	$	1,274,508		$	1,306,916
Unproved oil and gas properties		16,201			27,619

		1,290,709			1,334,535
Less accumulated depreciation, depletion, amortization and impairment		(1,190,359	)		(1,043,668	)

Net capitalized costs	$	100,350		$	290,867

Costs Incurred

The following table presents information regarding our net costs incurred in the purchase of proved and unproved properties and in exploration and development activities for the periods indicated (in thousands):


	Year Ended December 31,
	2020		2019
Property acquisition costs:
Unproved	$	1,508	$	12,486
Proved		—		168,838
Exploration costs		11,594		1,003
Development costs		5,819		41,273

Total costs incurred	$	18,921	$	223,600

Oil and Natural Gas Reserves

Proved reserves are the estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and current regulatory practices. Proved developed reserves are proved reserves which are expected to be produced from existing completion intervals with existing equipment and operating methods.

Proved oil and natural gas reserve quantities at December 31, 2020, 2019 and 2018, and the related discounted future net cash flows before income taxes are based on estimates prepared by William M. Cobb & Associates, Inc. and Netherland, Sewell & Associates, Inc. All estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission.

The below table summarizes the Company’s net ownership interests in estimated quantities of proved oil, natural gas and natural gas liquids (“NGLs”) reserves and changes in net proved reserves as of December 31, 2020, 2019 and 2018, all of which are located in the continental United States.


	Oil and Condensate			Natural Gas			NGLs			Total
	(MBbls)			(MMcf)			(MBbls)			(Mboe)
Proved Developed and Undeveloped Reserves as of:
December 31, 2018		9,434			54,206			3,517			21,985
Sale of minerals in place		(1	)		(371	)		(12	)		(75	)
Acquisitions		7,718			91,765			9,103			32,115
Extensions and discoveries		9,788			9,581			1,457			12,842
Revisions of previous estimates		(7,063	)		(14,359	)		(1,689	)		(11,146	)
Production		(791	)		(9,522	)		(612	)		(2,990	)

December 31, 2019		19,085			131,300			11,764			52,731

Sale of minerals in place		(142	)		(4,754	)		(238	)		(1,172	)
Acquisitions		—			—			—			—
Extensions and discoveries		2,074			423			184			2,328
Revisions of previous estimates		(6,339	)		(23,520	)		(3,294	)		(13,552	)
Production		(1,674	)		(18,967	)		(1,262	)		(6,097	)

December 31, 2020		13,004			84,482			7,154			34,238

Proved Developed Reserves as of:
December 31, 2018		3,103			46,840			2,297			13,206
December 31, 2019		9,819			122,691			10,484			40,752
December 31, 2020		7,166			82,788			6,595			27,558
Proved Undeveloped Reserves as of:
December 31, 2018		6,331			7,366			1,220			8,779
December 31, 2019		9,266			8,609			1,280			11,979
December 31, 2020		5,838			1,694			559			6,680

During the year ended December 31, 2020, our proved reserves decreased by approximately 18.5 MMBoe primarily due to a 21.1 MMBoe decrease related to negative revisions related to lower commodity prices, a 1.0 MMBoe decrease related to property sales in our Central Oklahoma and Western Anadarko regions and 2020 production of 6.1 MMBoe, partially offset by a 7.5 MMBoe increase related to positive performance revisions primarily in our Central Oklahoma and West Texas regions and a 2.3 MMBoe increase attributable to new PUD locations in our West Texas area.

During the year ended December 31, 2019, our proved reserves increased by approximately 30.7 MMBoe primarily due to the 32.1 MMBoe increase related to the White Star Acquisition and Will Energy Acquisition, as well as an increase in total reserves attributable to our recently drilled wells in the NE Bullseye area of West Texas, offset by 2019 production and a downward revision in Bullseye PUDs in West Texas related to the impact of the low commodity price environment on economics in the area, and the related timeline for expected development of those PUD locations over the next five years.

Standardized Measure

The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved oil and natural gas reserves as of December 31, 2020 and 2019 are shown below (in thousands):


	As of December 31,
	2020			2019
Future cash inflows	$	721,395		$	1,519,882
Future production costs		(411,069	)		(782,031	)
Future development costs		(101,723	)		(217,782	)
Future income tax expenses		(18,901	)		(43,913	)

Future net cash flows		189,702			476,156
10% annual discount for estimated timing of cash flows		(74,115	)		(218,314	)

Standardized measure of discounted future net cash flows	$	115,587		$	257,842

Future cash inflows represent expected revenues from production and are computed by applying certain prices of oil and natural gas to estimated quantities of proved oil and natural gas reserves. Prices are based on the first-day-of-the-month prices for the previous 12 months. As of December 31, 2020, future cash inflows were based on unadjusted prices of $39.57 per barrel of oil, $2.14 per MMBtu of natural gas and $12.43 per barrel of NGL. As of December 31, 2019, future cash inflows were based on unadjusted prices of $55.69 per barrel of oil, $2.52 per MMBtu of natural gas and $16.95 per barrel of NGL.

Realized Prices

The average realized prices for the year ended December 31, 2020 production were $37.31 per barrel of oil, $1.65 per MCF of gas and $13.54 per barrel of NGL. Sales are based on market prices and do not include the effects of realized derivative hedging gains of $25.3 million for the year ended December 31, 2020.

The average realized prices for the year ended December 31, 2019 production were $56.55 per barrel of oil, $2.35 per MCF of gas and $15.39 per barrel of NGL. Sales are based on market prices and do not include the effects of realized derivative hedging gains of $2.6 million for the year ended December 31, 2019.

Future production and development costs are estimated expenditures to be incurred in developing and producing the Company’s proved oil and natural gas reserves based on historical costs and assuming continuation of existing economic conditions. Future development costs relate to compression charges at our platforms, abandonment costs, recompletion costs and additional development costs for new facilities.

Future income taxes are based on year-end statutory rates, adjusted for tax basis and applicable tax credits. A discount factor of 10 percent was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Company’s oil and natural gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates of oil and natural gas producing operations.

Change in Standardized Measure

Changes in the standardized measure of future net cash flows relating to proved oil and natural gas reserves are summarized below (in thousands):


	Year Ended December 31,
	2020			2019
Changes in standardized measure due to current year operation:
Sales of oil and natural gas produced during the period, net of production expenses	$	(68,787	)	$	(55,868	)
Extensions and discoveries		4,729			54,308
Net change in prices and production costs		(78,046	)		(67,470	)
Changes in estimated future development costs		9,360			16,223
Revisions in quantity estimates		(48,609	)		(77,309	)
Purchase of reserves		—			177,007
Sale of reserves		(3,259	)		(246	)
Previously estimated development costs incurred		—			2,958
Accretion of discount		28,655			22,051
Changes in income taxes		17,922			(27,148	)
Change in the timing of production rates and other		(4,220	)		(5,608	)

Net change		(142,255	)		38,898
Beginning of year		257,842			218,944

End of year	$	115,587		$	257,842

During the year ended December 31, 2020, our proved reserves decreased by approximately 18.5 MMBoe, and our standardized measure decreased by approximately $142.3 million. This decrease is primarily attributable to lower commodity prices and the sales of non-core producing assets.

During the year ended December 31, 2019, our proved reserves increased by approximately 30.7 MMBoe, and our standardized measure increased by approximately $38.9 million. This increase is primarily attributable to the Will Energy Acquisition and White Star Acquisition.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY RESULTS OF OPERATIONS (Unaudited)

Quarterly Results of Operations

The following table sets forth the results of operations by quarter for the fiscal years ended December 31, 2020 and 2019 (in thousands, except per share amounts):


	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
Year ended December 31, 2020:
Revenues	$	34,573		$	17,842		$	31,348		$	29,157
Operating Loss (1)	$	(151,465	)	$	(21,275	)	$	2,058		$	(24,614	)
Net loss attributable to common stock (2)	$	(105,255	)	$	(28,034	)	$	(6,805	)	$	(25,248	)
Net loss per share (3):
Basic:	$	(0.80	)	$	(0.21	)	$	(0.05	)	$	(0.16	)
Diluted:	$	(0.80	)	$	(0.21	)	$	(0.05	)	$	(0.16	)
Year ended December 31, 2019:
Revenues	$	14,011		$	12,762		$	12,547		$	37,193
Operating Loss (1)	$	(4,553	)	$	(6,457	)	$	(8,794	)	$	(130,926	)
Net loss attributable to common stock (2)		(8,618	)		(4,961	)		(7,838	)		(138,379	)
Net loss per share (3):
Basic:	$	(0.26	)	$	(0.15	)	$	(0.19	)	$	(1.32	)
Diluted:	$	(0.26	)	$	(0.15	)	$	(0.19	)	$	(1.32	)

(1)	Represents oil, natural gas and NGL sales and fee for service revenues, less operating expenses, exploration expenses, depreciation, depletion and amortization, lease expirations and relinquishments, impairment of oil and natural gas properties and general and administrative expense.

(2)

Represents oil, natural gas and NGL sales, less operating expenses, exploration expenses, depreciation, depletion and amortization, lease expirations and relinquishments, impairment of oil and natural gas properties, general and administrative expense, and other income and expense after income taxes.

(3)	The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share as each quarterly computation is based on the income for that quarter and the weighted average number of common shares outstanding during that quarter.

Exhibit 99.4

Item 1.

Consolidated Financial Statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except number of shares)


	September 30, 2021			December 31, 2020

	(unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$	3,084		$	1,383
Accounts receivable, net		101,271			37,862
Prepaid expenses		6,801			3,360
Current derivative asset		—			2,996
Inventory		571			442
Deposits and other		—			763

Total current assets		111,727			46,806
PROPERTY, PLANT AND EQUIPMENT:
Oil and natural gas properties, successful efforts method of accounting:
Proved properties		1,610,533			1,274,508
Unproved properties		14,146			16,201
Other property & equipment		2,855			1,669
Accumulated depreciation, depletion, amortization and impairment		(1,183,606	)		(1,190,475	)

Total property, plant and equipment, net		443,928			101,903
OTHER NON-CURRENT ASSETS:
Investments in affiliates		4,896			6,793
Long-term derivative asset		—			497
Right-of-use lease assets		7,137			5,448
Debt issuance costs		3,582			1,782
Deposits		1,813			7,038

Total other non-current assets		17,428			21,558

TOTAL ASSETS	$	573,083		$	170,267

CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	173,608		$	83,970
Current derivative liability		71,702			1,317
Current asset retirement obligations		5,193			4,249

Total current liabilities		250,503			89,536
NON-CURRENT LIABILITIES:
Long-term debt		118,000			12,369
Long-term derivative liability		22,467			1,648
Asset retirement obligations		126,076			48,523
Lease liabilities		3,673			2,624

Total non-current liabilities		270,216			65,164

TOTAL LIABILITIES		520,719			154,700

COMMITMENTS AND CONTINGENCIES (NOTE 12)
SHAREHOLDERS’ EQUITY:
Common stock, $0.04 par value, 400,000,000 shares authorized, 201,435,797 shares issued and 201,175,841 shares outstanding at September 30, 2021, 173,830,390 shares issued and 173,737,816 shares outstanding at December 31, 2020		8,045			6,941
Additional paid-in capital		623,796			535,192
Treasury shares at cost (259,956 shares at September 30, 2021 and 92,574 shares at December 31, 2020)		(1,024	)		(248	)
Accumulated deficit		(578,453	)		(526,318	)

Total shareholders’ equity		52,364			15,567

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	573,083		$	170,267

The accompanying notes are an integral part of these consolidated financial statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020


	(unaudited)						(unaudited)
REVENUES:
Oil and condensate sales	$	56,044		$	17,415		$	149,246		$	48,127
Natural gas sales		26,241			7,930			55,556			22,718
Natural gas liquids sales		15,175			5,003			35,735			11,918
Other operating revenues		2,467			1,000			2,980			1,000

Total revenues		99,927			31,348			243,517			83,763
EXPENSES:
Operating expenses		44,916			14,586			108,901			48,859
Exploration expenses		174			(227	)		458			11,344
Depreciation, depletion and amortization		9,792			6,185			30,391			24,131
Impairment and abandonment of oil and natural gas properties		258			47			712			145,925
General and administrative expenses		14,599			8,699			39,441			24,186

Total expenses		69,739			29,290			179,903			254,445

OTHER INCOME (EXPENSE):
Loss from investment in affiliates, net of income taxes		(1,093	)		(126	)		(1,897	)		(13	)
Gain from sale of assets		113			38			461			4,471
Interest expense		(1,598	)		(1,057	)		(4,156	)		(4,421	)
Gain (loss) on derivatives, net		(48,390	)		(7,369	)		(117,951	)		30,526
Gain on extinguishment of debt		3,369			—			3,369			—
Other income		1,145			319			3,714			1,456

Total other income (expense)		(46,454	)		(8,195	)		(116,460	)		32,019

NET LOSS BEFORE INCOME TAXES		(16,266	)		(6,137	)		(52,846	)		(138,663	)
Income tax benefit (provision)		1,066			(668	)		711			(1,431	)

NET LOSS	$	(15,200	)	$	(6,805	)	$	(52,135	)	$	(140,094	)

NET LOSS PER SHARE:
Basic	$	(0.08	)	$	(0.05	)	$	(0.26	)	$	(1.07	)
Diluted	$	(0.08	)	$	(0.05	)	$	(0.26	)	$	(1.07	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		199,136			131,686			196,867			131,493
Diluted		199,136			131,686			196,867			131,493

The accompanying notes are an integral part of these consolidated financial statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Nine Months Ended September 30,
	2021			2020

	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(52,135	)	$	(140,094	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		30,391			24,131
Impairment and abandonment of oil and natural gas properties		72			145,938
Exploration expenditures - dry hole costs		—			10,421
Amortization of debt issuance costs		734			1,486
Deferred income taxes		—			676
Gain on sale of assets		(461	)		(4,471	)
Loss from investment in affiliates		1,897			13
Stock-based compensation		8,090			2,378
Non-cash mark-to-market loss (gain) on derivative instruments		96,240			(8,155	)
Gain on extinguishment of debt		(3,369	)		—
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable & other receivables		(49,529	)		7,489
Increase in prepaid expenses		(3,216	)		(1,894	)
Increase in inventory		(129	)		(305	)
Increase (decrease) in accounts payable & advances from joint owners		32,549			(2,122	)
Increase (decrease) in other accrued liabilities		21,971			(9,000	)
Decrease in income taxes receivable, net		268			281
Increase (decrease) in income taxes payable		(2,026	)		119
Decrease (increase) in deposits and other		7,138			(328	)

Net cash provided by operating activities	$	88,485		$	26,563

CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas exploration and development expenditures	$	(11,040	)	$	(22,209	)
Acquisition of oil & natural gas properties		(183,724	)		—
Proceeds from sales of oil & natural gas properties		2,800			339
Additions to furniture & equipment		(942	)		(171	)

Net cash used in investing activities	$	(192,906	)	$	(22,041	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under Credit Agreement	$	267,800		$	58,000
Repayments under Credit Agreement		(158,800	)		(64,768	)
Paycheck Protection Program loan		—			3,369
Net proceeds from equity offering		432			410
Purchase of treasury stock		(776	)		(188	)
Debt issuance costs		(2,534	)		—

Net cash provided by (used in) financing activities	$	106,122		$	(3,177	)

NET CHANGE IN CASH AND CASH EQUIVALENTS	$	1,701		$	1,345
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		1,383			1,624

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	3,084		$	2,969

The accompanying notes are an integral part of these consolidated financial statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

For the nine months ended September 30, 2021

(in thousands, except number of shares)


	Common Stock					Additional			Treasury Stock			Accumulated			Total Shareholders’
	Shares			Amount		Paid-in Capital			Treasury Stock			Deficit			Equity

	(unaudited)
Balance at December 31, 2020		173,737,816		$	6,941	$	535,192		$	(248	)	$	(526,318	)	$	15,567
Equity offering - common stock		117,000			5		448			—			—			453
Mid-Con Acquisition		25,409,164			1,015		78,514			—			—			79,529
Treasury shares at cost		(33,587	)		—		—			(166	)		—			(166	)
Restricted shares activity		37,041			2		(2	)		—			—			—
Stock-based compensation		—			—		1,797			—			—			1,797
Net loss		—			—		—			—			(4,293	)		(4,293	)

Balance at March 31, 2021		199,267,434		$	7,963	$	615,949		$	(414	)	$	(530,611	)	$	92,887

Equity offering - common stock		60,613			2		(22	)		—			—			(20	)
Mid-Con Acquisition		143,769			6		448			—			—			454
Stock issuance for prospect costs		387,011			16		1,096			—			—			1,112
Treasury shares at cost		(131,894	)		—		—			(602	)		—			(602	)
Restricted shares activity		1,455,326			58		(58	)		—			—			—
Stock-based compensation		—			—		3,182			—			—			3,182
Net loss		—			—		—			—			(32,642	)		(32,642	)

Balance at June 30, 2021		201,182,259		$	8,045	$	620,595		$	(1,016	)	$	(563,253	)	$	64,371

Treasury shares at cost		(1,901	)		—		—			(8	)		—			(8	)
Restricted shares activity		(4,517	)		—		—			—			—			—
Stock-based compensation		—			—		3,201			—			—			3,201
Net loss		—			—		—			—			(15,200	)		(15,200	)

Balance at September 30, 2021		201,175,841		$	8,045	$	623,796		$	(1,024	)	$	(578,453	)	$	52,364

The accompanying notes are an integral part of these consolidated financial statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

For the nine months ended September 30, 2020

(in thousands, except number of shares)


	Series C Preferred Stock						Common Stock					Additional Paid-in Capital			Treasury Stock			Accumulated Deficit			Total Shareholders’ Equity
	Shares			Amount			Shares			Amount		Additional Paid-in Capital			Treasury Stock			Accumulated Deficit			Total Shareholders’ Equity

	(unaudited)
Balance at December 31, 2019		2,700,000		$	108			128,977,816		$	5,148	$	471,778		$	(18	)	$	(360,976	)	$	116,040
Equity offering - common stock		—			—			—			—		(47	)		—			—			(47	)
Treasury shares at cost		—			—			(49,474	)		—		—			(157	)		—			(157	)
Restricted shares activity		—			—			77,485			3		(3	)		—			—			—
Stock-based compensation		—			—			—			—		350			—			—			350
Net loss		—			—			—			—		—			—			(105,255	)		(105,255	)

Balance at March 31, 2020		2,700,000		$	108			129,005,827		$	5,151	$	472,078		$	(175	)	$	(466,231	)	$	10,931

Equity offering - common stock		—			—			155,029			6		477			—			—			483
Conversion of preferred stock to common stock		(2,700,000	)		(108	)		2,700,000			108		—			—			—			—
Treasury shares at cost		—			—			(13,808	)		—		—			(23	)		—			(23	)
Restricted shares activity		—			—			149,709			6		(6	)		—			—			—
Stock-based compensation		—			—			—			—		265			—			—			265
Net loss		—			—			—			—		—			—			(28,034	)		(28,034	)

Balance at June 30, 2020		—		$	—			131,996,757		$	5,271	$	472,814		$	(198	)	$	(494,265	)	$	(16,378	)

Equity offering - common stock		—			—			8,900			—		(27	)		—			—			(27	)
Treasury shares at cost		—			—			(3,678	)		—		—			(8	)		—			(8	)
Restricted shares activity		—			—			1,011,699			41		(41	)		—			—			—
Stock-based compensation		—			—			—			—		1,764			—			—			1,764
Net loss		—			—			—			—		—			—			(6,805	)		(6,805	)

Balance at September 30, 2020		—		$	—			133,013,678		$	5,312	$	474,510		$	(206	)	$	(501,070	)	$	(21,454	)

The accompanying notes are an integral part of these consolidated financial statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.	Organization and Business

Contango Oil & Gas Company (collectively with its subsidiaries, “Contango” or the “Company”) is a Fort Worth, Texas based independent oil and natural gas company. The Company’s business is to maximize production and cash flow from its onshore properties primarily located in its Midcontinent, Permian, Rockies and other smaller onshore areas and its offshore properties in the shallow waters of the Gulf of Mexico and utilize that cash flow to explore, develop and acquire oil and natural gas properties across the United States.

The following table lists the Company’s primary producing regions as of September 30, 2021:


Region		Formation
Midcontinent		Cleveland, Bartlesville, Mississippian, Woodford and others
Permian		San Andres, Yeso, Bone Springs, Wolfcamp and others
Rockies		Sussex, Shannon, Muddy, Phosphoria, Embar-Tensleep, Frontier, Fort Union, Lance, Mesa Verde, Codey, Madison and others
Other		Woodbine, Lewisville, Buda, Georgetown, Eagleford, Offshore Gulf of Mexico properties in water depths off of Louisiana in less than 300 feet, and others

Impact of the COVID-19 Pandemic

The coronavirus (“COVID-19”) pandemic has significantly affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the COVID-19 pandemic has resulted in travel restrictions, business closures and other restrictions that have disrupted the demand for oil throughout the world and, when combined with the failure by the Organization of Petroleum Exporting Countries (“OPEC”) and Russia to reach an agreement on lower production quotas until April 2020, resulted in oil prices declining significantly beginning in late February 2020. While there has been an improvement in commodity prices since early 2020, prices remain volatile, and there is still significant uncertainty regarding the long-term impact of the COVID-19 pandemic on global oil demand and prices. Due to the extreme volatility in oil prices and the impact of the COVID-19 pandemic on the financial condition of the Company’s upstream peers, the Company suspended its onshore drilling program in the Southern Delaware Basin in the first quarter of 2020, further suspended all drilling in the second quarter of 2020, and then focused on certain measures that included, but have not been limited to, the following:

•

a company-wide effort to cut costs throughout the Company’s operations;

•

potential acquisitions of PDP-heavy assets, with attractive, discounted valuations, in stressed/distressed scenarios or from non-natural owners such as investment or lender firms that obtained ownership through a corporate restructuring;

•

the identification of more cost-efficient drilling and completion strategies by the Company’s technical teams and the possible commencement of a conservative drilling/completion program on undeveloped opportunities in the Company’s portfolio should oil prices, and market stability, continue to improve and provide appropriate risk-weighted returns; and

•

the extensive review of assets acquired in recent transactions for cost reduction opportunities, as well as opportunities to return to production wells that had been shut-in by the previous owners due to limited capital resources.

Corporate Overview and Capital Allocation

Drilling Program

From the Company’s initial entry into the Southern Delaware Basin in 2016 and through early 2019, the Company was focused on the development of its Southern Delaware Basin acreage in Pecos County, Texas. Due to the extreme volatility in oil prices and the impact of the COVID-19 pandemic on the financial condition of the Company’s upstream peers, the Company suspended its onshore drilling program in the Southern Delaware Basin in the first quarter of 2020 and further suspended all drilling in the second quarter of 2020. Due to strengthening oil prices in 2021 and the Company’s identification of more cost-efficient methods of drilling and completing its Permian Basin wells, the Company resumed a conservative one-rig drilling program in the Southern Delaware Basin in the second quarter of 2021. In May 2021, the Company began drilling the first of three single-pad wells originally planned in the Southern Delaware Basin in the Permian region. Based on recent success by other operators adjacent to the Company’s position, the Company decided to drill one of the three wells in this first pad to the Second Bone Spring formation, which is the first Company well drilled to that formation. Due to the success and efficiency in the drilling of these first three wells and the improved oil price market, the Company commenced spudding a second three-well pad in July 2021 as part of its 2021 Permian drilling program. The first two wells, both drilled to the Wolfcamp A formation, were drilled to an average total measured depth of 20,440 feet with an average lateral length of 9,700 feet and 48 stages of fracture stimulation. The third well, drilled to the Second Bone Spring formation, was drilled to a total measured depth of 19,090 feet with a lateral length of 9,574 feet and 47 stages of fracture stimulation. These three wells were brought online in mid-October and are still being evaluated at this time. The Company plans to begin completion operations on the second three wells in late November, with first production expected in January 2022. As of September 30, 2021, the Company was producing from eighteen wells over its approximate 16,200 gross operated (7,500 company net) acre position in its Permian region, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations.

During the nine months ended September 30, 2021, the Company incurred capital drilling and completion expenditures of approximately $13.2 million related to the Southern Delaware Basin wells. The Company also incurred approximately $10.2 million in expenditures for redevelopment activities primarily related to acquired properties in the Midcontinent, Permian and Rockies regions and $2.3 million in unproved offshore prospect costs, of which $1.1 million was paid for with the proceeds of an issuance of Company common stock, pursuant to a joint development agreement between the Company and Juneau Oil & Gas, LLC. The Company currently forecasts its 2021 capital expenditure budget to be a total of $30.0 – $34.0 million for recompletions, facility upgrades, waterflood development and the select drilling in the West Texas Permian (3 net locations, 6 gross locations), among other things. This forecast does not account for the Pending Independence Merger. The planned capital expenditures also include development opportunities with respect to certain properties acquired by the Company as part of the Mid-Con Acquisition and the Silvertip Acquisition (both as defined below). The capital expenditure program will continue to be evaluated for revision for the remainder of the year. The Company believes that its internally generated cash flow will be more than adequate to fund its 2021 capital expenditure budget and any increase to such 2021 capital expenditure budget, when and if such increase is deemed appropriate. The Company plans to retain the flexibility to be more aggressive in its drilling plans should results exceed expectations, commodity prices continue to improve or if the Company reduces drilling and completion costs in certain areas, thereby making an expansion of its drilling program an appropriate business decision.

For the remainder of 2021, the Company plans to continue to make balance sheet strength a priority. Any excess cash flow will likely be used to reduce borrowings outstanding under the Company’s Credit Agreement (as defined below). The Company intends to keenly focus on continuing to reduce lease operating costs on its legacy and recently acquired assets, reducing general and administrative expenses, improving cash margins and lowering its exposure to asset retirement obligations through the possible sale of non-core properties.

Acquisitions

On January 21, 2021, the Company closed on the acquisition of Mid-Con Energy Partners, LP (“Mid-Con”), in an all-stock merger transaction in which Mid-Con became a direct, wholly owned subsidiary of Contango (the “Mid-Con Acquisition”). A total of 25,552,933 shares of Contango common stock were issued as consideration in the Mid-Con Acquisition. Effective upon the closing of the Mid-Con Acquisition, the Company’s borrowing base under its Credit Agreement increased from $75.0 million to $130.0 million, with an automatic $10.0 million reduction in the borrowing base on March 31, 2021. See Note 3 – “Acquisitions and Dispositions” and Note 10 – “Long-Term Debt” for further details.

On February 1, 2021, the Company closed on the acquisition of certain oil and natural gas properties located in the Big Horn Basin in Wyoming and Montana, in the Powder River Basin in Wyoming and in the Permian Basin in West Texas and New Mexico (collectively the “Silvertip Acquisition”) for aggregate consideration of approximately $58.0 million. After customary closing adjustments, including the results of operations during the period between the effective date of August 1, 2020 and the closing date, the net consideration paid was approximately $53.3 million. See Note 3 – “Acquisitions and Dispositions” for more information.

On June 7, 2021, the Company entered into a definitive agreement to combine with Independence Energy, LLC (“Independence”) in an all-stock transaction (the “Pending Independence Merger”). Independence is a diversified, well-capitalized upstream oil and gas business built and managed by KKR’s Energy Real Assets team with a scaled portfolio of low-decline, producing assets with meaningful reinvestment opportunities for low-risk growth across the Eagle Ford, Rockies, Permian and Mid-Continent regions. The closing of the Pending Independence Merger remains subject to the approval of the Company’s stockholders at the Special Meeting of the Stockholders to be held on December 6, 2021, and is expected to be completed in December 2021. The Pending Independence Merger agreement includes certain restrictions on the conduct of the business of the Company until the closing, such as a requirement to operate in the ordinary course of business and limitations on, among other things, the Company’s ability to make acquisitions, declare or pay dividends, issue or sell equity or incur debt. Upon completion of the Pending Independence Merger, existing Independence shareholders are expected to own approximately 76% and existing Contango shareholders are expected to own approximately 24% of the combined company. See Note 3 – “Acquisitions and Dispositions” and Note 13 – “Subsequent Events” for further details.

On August 31, 2021, the Company closed on the acquisition of low decline, conventional gas assets in the Wind River Basin of Wyoming (the “Wind River Basin Acquisition”). Upon closing, Contango acquired approximately 446 Bcfe of PDP reserves (unaudited) for a total purchase price of $67.0 million in cash. After customary closing adjustments, including the results of operations during the period between the effective date of June 1, 2021 and the closing date, the net consideration paid was approximately $62.6 million, subject to customary purchase price adjustments. See Note 3 – “Acquisitions and Dispositions” for further details.

Other

On April 28, 2021, the Company adopted the Contango Oil & Gas Company Change in Control Severance Plan (the “Change in Control Plan”), which provides “double trigger” severance payments and benefits to all employees including the Company’s named executive officers. The policy provides an eligible participant with certain payments and benefits in the event that the participant experiences a qualifying termination event within the 12-month period following a change in control. In the event that an eligible executive’s employment is terminated without cause by the employer or for good reason by the executive within the 18-month period following the occurrence of a change in control, the Company’s Chief Executive Officer and the Company’s President would become entitled to receive 250%, and the Company’s Senior Vice President and Chief Financial Officer would become entitled to receive 200%, of the sum of the executive’s annual base salary and target annual cash bonus. In addition, the executive would receive (1) any unpaid cash bonus for the year preceding the year of termination based on actual performance; (2) Company-paid COBRA continuation coverage for up to 18 months following the date of termination; (3) reimbursement for up to $10,000 in outplacement services; and (4) any outstanding unvested PSU equity awards (defined below) held by the executive will remain outstanding and vest based on the greatest of (a) actual performance through the execution date of the definitive documentation governing the change in control, (b) actual performance through the date of the participant’s termination of employment, or (c) the target number of shares granted under such PSU award. The Change in Control Plan contains a modified cutback provision whereby payments payable to an executive may be reduced if doing so would put the executive in a more advantageous after-tax provision than if payments were not reduced and the executive became subject to excise taxes under Section 4999 of the Code.

On April 28, 2021, the Company adopted the Contango Oil & Gas Company Executive Severance Plan (the “Severance Plan”), which provides severance payments and benefits to its named executive officers outside the context of a change in control. The Severance Plan provides an eligible participant with payments and benefits in the event of involuntary termination without cause or other termination due to a good reason. In the event of such a

qualifying termination under the Severance Plan, the participant would become entitled to receive in the case of the Company’s Chief Executive Officer and the Company’s President, 150%, and in the case of the Company’s Senior Vice President and Chief Financial Officer, 100%, of the sum of the participant’s annual base salary and target bonus. In addition, the participant would receive (1) any unpaid annual cash bonus for the year preceding the year of termination based on actual performance; (2) Company-paid COBRA continuation coverage for up to 18 months following the date of termination; (3) reimbursement for up to $10,000 in outplacement services; (4) all outstanding unvested time-based equity awards held by the executive will 100% accelerate and become exercisable or settle (as applicable); and (5) a pro-rated portion of any outstanding unvested PSU awards held by the executive will remain outstanding and vest based on actual performance over the applicable performance period.

On May 3, 2021, the Company entered into the Fifth Amendment to the Credit Agreement (the “Fifth Amendment”) which provided for, among other things, an increase in the Company’s borrowing base from $120.0 million to $250.0 million, effective May 3, 2021, and expanded the bank group from nine to eleven banks. The Fifth Amendment also includes less restrictive hedge requirements and certain modifications to financial covenants. See Note 10 – “Long-Term Debt” for more information.

In light of the Pending Independence Merger, on October 28, 2021, the Company, JPMorgan Chase Bank, N.A. and the lenders under the Credit Agreement entered into a waiver letter which, among other things, postpones the November 2021 scheduled redetermination of the Company’s borrowing base until on or about February 1, 2022. See Note 10 – “Long-Term Debt” and Note 13 – “Subsequent Events” for further details.

2.	Summary of Significant Accounting Policies

The accounting policies followed by the Company are set forth in the notes to the Company’s audited consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2020 (“2020 Form 10-K”) filed with the Securities and Exchange Commission (“SEC”). Please refer to the notes to the financial statements included in the 2020 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. No material items included in those notes have changed except as a result of normal transactions in the interim or as disclosed within this interim report.

Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information, pursuant to the rules and regulations of the SEC, including instructions to Quarterly Reports on Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, all adjustments considered necessary for a fair statement of the unaudited consolidated financial statements have been included. All such adjustments are of a normal recurring nature. The consolidated financial statements should be read in conjunction with the 2020 Form 10-K. These unaudited interim consolidated results of operations for the nine months ended September 30, 2021 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2021.

The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries after elimination of all material intercompany balances and transactions. All wholly owned subsidiaries are consolidated. The Company’s investment in Exaro Energy III LLC (“Exaro”), through its wholly owned subsidiary, Contaro Company, is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results, production or reserves in those reported for the Company’s consolidated results of operations.

Certain amounts in prior-period financial statements have been reclassified to conform to the current period’s presentation. On the consolidated statements of operations, the Company’s working interest percentage share of the overhead billed to the 8/8s joint account for wells it operates has been reclassified from operating expenses to general and administrative expenses.

Oil and Natural Gas Properties – Successful Efforts

The Company’s application of the successful efforts method of accounting for its oil and natural gas exploration and production activities requires judgment as to whether particular wells are developmental or exploratory, since lease acquisition costs and all development costs are capitalized, whereas exploratory drilling costs are continuously capitalized until the results are determined. If proved reserves are not discovered, the drilling costs are expensed as exploration costs. Other exploration related costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred.

The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive, but then actually deliver oil and natural gas in quantities insufficient to be economic, which may result in the abandonment and/or impairment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive oil or natural gas field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas, and therefore, management must estimate the portion of seismic costs to expense as exploratory.

The evaluation of oil and natural gas leasehold acquisition costs included in unproved properties for write-off or impairment requires management’s judgment on exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

Impairment of Long-Lived Assets

Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field-by-field basis to the unamortized capitalized cost of the assets in that field. If the estimated future undiscounted cash flows, based on the Company’s estimate of future reserves, oil and natural gas prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties. Additionally, the Company may use appropriate market data to determine fair value. No impairment of proved properties was recorded during the nine months ended September 30, 2021.

Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value of those properties, with any such impairment charged to expense in the period. The Company recorded a $0.2 million non-cash charge for unproved impairment expense during the nine months ended September 30, 2021 related to expiring leases in the Company’s Permian region. The Company recorded a $2.6 million non-cash charge for unproved impairment expense during the nine months ended September 30, 2020 related to expiring leases in the Company’s Midcontinent region.

Net Loss Per Common Share

Basic net loss per common share is computed by dividing the net loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net loss per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Potentially dilutive securities, including unexercised stock options, performance stock units and unvested restricted stock, have not been considered when their effect would be antidilutive. The Company excluded 4,914 shares or units and 53,106 shares or units of potentially dilutive securities during the three and nine months ended September 30, 2021, respectively, as they were antidilutive. The Company excluded 924,082 shares or units and 480,426 shares or units of potentially dilutive securities during the three and nine months ended September 30, 2020, respectively, as they were antidilutive.

Subsidiary Guarantees

Contango Oil & Gas Company, as the parent company of its subsidiaries, filed a registration statement on Form S-3 on December 18, 2020 with the SEC to register, among other securities, debt securities that the Company may issue from time to time. Contango Resources, Inc., Contango Midstream Company, Contango Operators, Inc., Contaro Company, Contango Alta Investments, Inc. and any other of the Company’s future subsidiaries specified in any future prospectus supplement (each a “Subsidiary Guarantor”) are co-registrants with the Company under the registration statement, and the registration statement also registered guarantees of debt securities by such Subsidiary Guarantors. The Subsidiary Guarantors are wholly-owned by the Company, either directly or indirectly, and any guarantee by the Subsidiary Guarantors will be full and unconditional. The Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Company. Finally, the Company’s wholly-owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party.

Revenue Recognition

Sales of oil, condensate, natural gas and natural gas liquids (“NGLs”) are recognized at the time control of the products are transferred to the customer. Generally, the Company’s gas processing and purchase agreements indicate that the processors take control of the Company’s gas at the inlet of the plant, and that control of residue gas is returned to the Company at the outlet of the plant. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs. The Company delivers oil and condensate to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product.

Generally, the Company’s contracts have an initial term of one year or longer but continue month to month unless written notification of termination in a specified time period is provided by either party to the contract. The Company receives purchaser statements from the majority of its customers, but there are a few contracts where the Company prepares the invoice. Payment is unconditional upon receipt of the statement or invoice. Based upon the Company’s past experience with its current purchasers and expertise in the market, collectability is probable, and there have not been payment issues with the Company’s purchasers over the past year or currently.

Leases

use, or control the use of, a specified asset for the lease term on the Company’s consolidated balance sheet. The Company does not include leases with an initial term of less than twelve months on the balance sheet. The Company recognizes payments on these leases within “Operating expenses” on its consolidated statements of operations. The Company has modified procedures to its existing internal controls to review any new contracts which contain a physical asset on a quarterly basis and determine if an arrangement is, or contains, a lease at inception. The Company will continue to review all new or modified contracts on a quarterly basis for proper treatment. See Note 7 – “Leases” for additional information.

Recent Accounting Pronouncements

In August 2018, the FASB issued ASU 2018-15, Intangibles – Goodwill and Other Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The new guidance aligns the requirement for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirement for capitalizing implementation costs incurred to develop or obtain internal-use-software (and hosting arrangements that include an internal-use software license). ASU 2018-15 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2019. The Company adopted ASU 2018-15 on January 1, 2020 on a prospective basis. Accordingly, the Company capitalized $0.8 million in implementation costs incurred in a cloud computing arrangement that is a service contract which are included in “Prepaid expenses” on the Company’s consolidated balance sheet as of September 30, 2021. Such capitalized costs will be amortized over the term of the hosting arrangement, commencing when the capitalized asset is ready for its intended use, which is expected to be in early 2022. Costs related to preliminary project activities and post-implementation activities are expensed as incurred.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including the Company’s trade and joint interest billing receivables. Allowances are to be measured using a current expected credit loss model as of the reporting date that is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model that increases the allowance when losses are probable. Initially, ASU 2016-13 was effective for all public companies for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and will be applied with a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The FASB subsequently issued ASU 2019-04 (“ASU 2019-04”), Codification Improvements to Financial Instruments – Credit Losses (Topic 326), Derivatives (Topic 815) and Financial Instruments (Topic 825) and ASU 2019-05 (“ASU 2019-05”), Financial Instruments – Credit Losses (Topic 326): Targeted Transition Relief. ASU 2019-04 and ASU 2019-05 provide certain codification improvements related to implementation of ASU 2016-13 and targeted transition relief consisting of an option to irrevocably elect the fair value option for eligible instruments. In November 2019, the FASB issued ASU 2019-10, Financial Instruments – Credit Losses (Topic 326), Derivatives and Hedging (Topic 815) and Leases (Topic 842): Effective Dates. This amendment deferred the effective date of ASU 2016-13 from January 1, 2020 to January 1, 2023 for calendar year-end smaller reporting companies, which includes the Company. The Company plans to defer the implementation of ASU 2016-13, and the related updates.

3.	Acquisitions and Dispositions

Wind River Basin Acquisition

On August 31, 2021, the Company closed on the acquisition of low decline, conventional gas assets in the Wind River Basin of Wyoming. Upon closing, Contango acquired approximately 446 Bcfe of PDP reserves (unaudited) for a total purchase price of $67.0 million in cash. After customary closing adjustments of $4.4 million, including the results of operations during the period between the effective date of June 1, 2021 and the closing date, the net consideration paid was approximately $62.6 million, subject to customary purchase price adjustments.

The Wind River Basin Acquisition was accounted for as an asset acquisition under FASB ASC 805, Business Combinations (“ASC 805”). Under the accounting for asset acquisitions, the Wind River Basin Acquisition was recorded using a cost accumulation and allocation model under which the cost of the acquisition was allocated on a relative fair value basis to the assets acquired and liabilities assumed. As an asset acquisition, acquisition-related transaction costs are capitalized as a component of the cost of the assets acquired.

Pending Independence Merger

On June 7, 2021, the Company entered into a definitive agreement to combine with Independence in an all-stock transaction. Independence is a diversified, well-capitalized upstream oil and gas business built and managed by KKR’s Energy Real Assets team with a scaled portfolio of low-decline, producing assets with meaningful reinvestment opportunities for low-risk growth across the Eagle Ford, Rockies, Permian and Mid-Continent regions. The closing of the Pending Independence Merger remains subject to the approval of the Company’s stockholders at the Special Meeting of the Stockholders to be held on December 6, 2021, and is expected to be completed in December 2021. The Pending Independence Merger agreement includes certain restrictions on the conduct of the business of the Company until the closing, such as a requirement to operate in the ordinary course of business and limitations on, among other things, the Company’s ability to make acquisitions, declare or pay dividends, issue or sell equity or incur debt. Upon completion of the Pending Independence Merger, existing Independence shareholders are expected to own approximately 76% and existing Contango shareholders are expected to own approximately 24% of the combined company. See Note 13 – “Subsequent Events” for further details.

Silvertip Acquisition

On November 27, 2020, the Company entered into a purchase agreement (“the Purchase Agreement”) to acquire certain oil and natural gas properties located in the Big Horn Basin in Wyoming and Montana, in the Powder River Basin in Wyoming and in the Permian Basin in West Texas and New Mexico, for aggregate consideration of approximately $58.0 million in cash. In connection with the execution of the Purchase Agreement, the Company paid $7.0 million as a deposit for its obligations under the Purchase Agreement, which is included in the consolidated balance sheet as of December 31, 2020. The Silvertip Acquisition closed on February 1, 2021. After customary closing adjustments of $4.7 million, including the results of operations during the period between the effective date of August 1, 2020 and the closing date, the net consideration paid was approximately $53.3 million, including the deposit previously paid in 2020. The Silvertip Acquisition was accounted for as an asset acquisition under ASC 805.

A summary of the consideration paid and the preliminary relative fair value of the assets acquired and liabilities assumed, which is subject to change based upon the final settlement statement, is as follows (in thousands):


	Purchase Price Allocation
Consideration:
Purchase price	$	58,000
Closing adjustments		(4,739	)

Total consideration		53,261
Acquisition transaction costs		109

Total cash paid	$	53,370

Fair value of liabilities assumed:
Accounts payable	$	423
Lease liabilities		1,014
Asset retirement obligations		32,367

Total relative fair value of liabilities assumed	$	33,804

Fair value of assets acquired:
Proved oil and natural gas properties	$	86,160
Right-of-use lease assets		1,014

Total relative fair value of assets acquired	$	87,174

In July of 2021, the Company paid $2.4 million in cash to purchase additional working interest in certain wells which were originally acquired in the Silvertip Acquisition and located in the Company’s Rockies region.

Mid-Con Acquisition

On October 25, 2020, the Company entered into an Agreement and Plan of Merger with Mid-Con and Mid-Con Energy GP, LLC, the general partner of Mid-Con (“Mid-Con GP”), pursuant to which Mid-Con would merge with and into Michael Merger Sub LLC, a Delaware limited liability company and a wholly-owned, direct subsidiary of the Company. The Mid-Con Acquisition, which closed on January 21, 2021, was unanimously approved by the conflicts committee of the board of directors of Mid-Con, by the full board of directors of Mid-Con, by the disinterested directors of the board of directors of the Company and was subject to shareholder and unitholder approvals and other customary conditions to closing. At the effective time of the Mid-Con Acquisition (the “Effective Time”), each common unit representing limited partner interests in Mid-Con issued and outstanding immediately prior to the Effective Time (other than treasury units or units held by Mid-Con GP) was converted automatically into the right to receive 1.75 shares of the Company’s common stock. A total of 25,552,933 shares of Contango common stock were issued as consideration in the Mid-Con Acquisition. As of January 21, 2021, John C. Goff, Chairman of the Board of Directors of the Company, beneficially owned approximately 56.4% of the common units of Mid-Con, and Travis Goff, John C. Goff’s son and the President of Goff Capital, Inc., served on the board of directors of the general partner of Mid-Con. The Company’s senior management team is running the combined company, and Contango’s board of directors remains intact as the board of directors of the combined company. The combined company is headquartered in Fort Worth, Texas.

The Mid-Con Acquisition was accounted for as a business combination using the acquisition method of accounting under ASC 805. Therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by the Company in determining the fair value of the oil and natural gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and natural gas reserves, expectations for the timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The preliminary purchase price assessment remains an ongoing process and is subject to change for up to one year subsequent to the closing of the Mid-Con Acquisition.

The following table sets forth the Company’s preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date (in thousands):


	Purchase Price Allocation
Consideration:
Mid-Con outstanding units		14,602
Exchange ratio of Contango shares for Mid-Con common units		1.75

Contango common stock to be issued to Mid-Con unitholders		25,553
Issue price	$	3.13

Stock consideration	$	79,979
Cash consideration in lieu of fractional shares		4
Payment of revolving credit facility		68,667

Total consideration	$	148,650

Fair value of liabilities assumed:
Accounts payable	$	8,892
Asset retirement obligations		28,252

Total fair value of liabilities assumed	$	37,144

Fair value of assets acquired:
Cash and cash equivalents	$	3,110
Accounts receivable		5,191
Current derivative asset		1,544
Prepaid expenses		225
Proved oil and natural gas properties		174,331
Other property and equipment		243
Other non-current assets		1,150

Total fair value of assets acquired	$	185,794

Pro Forma Information

The following unaudited pro forma combined condensed financial data for the year ended December 31, 2020 was derived from the historical financial statements of the Company after giving effect to the Mid-Con Acquisition and the Silvertip Acquisition, as if they had occurred on January 1, 2020. The below information reflects pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including the depletion of the fair-valued proved oil and natural gas properties acquired in the Mid-Con Acquisition and the Silvertip Acquisition. The pro forma results of operations do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the assets acquired. The pro forma consolidated statement of operations data has been included for comparative purposes only, is not necessarily indicative of the results that might have occurred had the acquisition taken place on January 1, 2020 and is not intended to be a projection of future results.


	Year Ended December 31, 2020
	(In thousands except for per share amounts)
	(unaudited)
Revenues	$	202,442
Net loss	$	(191,975	)
Basic loss per share	$	(0.97	)
Diluted loss per share	$	(0.97	)

Dispositions

During the nine months ended September 30, 2021, the Company sold certain non-core Powder River Basin producing properties in Wyoming, which were acquired in the first quarter of 2021 as part of the Silvertip Acquisition. The Company also sold certain non-core, legacy and recently acquired producing and non-producing properties located in its Midcontinent, Permian and Other regions. These properties were sold for a collective total of approximately $2.8 million in cash and the buyers’ assumption of approximately $5.1 million in plugging and abandonment liabilities, resulting in a net gain of $0.5 million recorded during the nine months ended September 30, 2021.

During the nine months ended September 30, 2020, the Company sold certain producing and non-producing properties located in its Midcontinent region. These properties were sold for approximately $0.5 million in cash and the buyers’ assumption of approximately $5.0 million in plugging and abandonment liabilities and revenue held in suspense. The Company recorded a gain of $4.5 million, primarily as a result of the buyers’ assumption of the asset retirement obligations associated with the sold properties.

4.	Fair Value Measurements

The Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. Fair value is 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 (exit price). A fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value as of September 30, 2021. A financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have been no transfers between Level 1, Level 2 or Level 3.

Fair value information for financial assets and liabilities was as follows as of September 30, 2021 (in thousands):


				Fair Value Measurements Using
	Total Carrying Value			Level 1		Level 2			Level 3
Derivatives
Commodity price contracts - assets	$	—		$	—	$	—		$	—
Commodity price contracts - liabilities	$	(94,169	)	$	—	$	(94,169	)	$	—

Derivatives listed above are recorded in “Current derivative asset or liability” and “Long-term derivative asset or liability” on the Company’s consolidated balance sheets and include swaps and costless collars that are carried at fair value. The Company records the net change in the fair value of these positions in “Gain (loss) on derivatives, net” in its consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 5 – “Derivative Instruments” for additional discussion of derivatives.

As of September 30, 2021, the Company’s derivative contracts were all with major institutions with investment grade credit ratings which are believed to have minimal credit risk, which primarily are lenders within the Company’s bank group. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance.

Estimates of the fair value of financial instruments are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s Credit Agreement approximates carrying value because the facility interest rate approximates current market rates and is reset at least every quarter. See Note 10 – “Long-Term Debt” for further information.

Impairments

The Company tests proved oil and natural gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. The Company estimates the undiscounted future cash flows expected in connection with the oil and natural gas properties on a field-by-field basis and compares such future cash flows to the unamortized capitalized costs of the properties. If the estimated future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties. Additionally, the Company may use appropriate market data to determine fair value. Because these significant fair value inputs are typically not observable, impairments of long-lived assets are classified as a Level 3 fair value measure.

Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period.

Asset Retirement Obligations

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and natural gas properties. The factors used to determine fair value include, but are not limited to, estimated future plugging and abandonment costs and expected lives of the related reserves. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3.

5.	Derivative Instruments

The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are typically utilized to hedge the Company’s exposure to price fluctuations and reduce the variability in the Company’s cash flows associated with anticipated sales of future oil and natural gas production. The Company typically hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. The Company believes that these derivative arrangements, although not free of risk, allow it to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of oil, natural gas and natural gas liquids sales. Moreover, because its derivative arrangements apply only to a portion of its production, the Company’s strategy provides only partial protection against declines in commodity prices. Such arrangements may expose the Company to risk of financial loss in certain circumstances. The Company continuously reevaluates its hedging program in light of changes in production, market conditions, commodity price forecasts and requirements under its Credit Agreement.

As of September 30, 2021, the Company’s oil and natural gas derivative positions consisted of swaps and costless collars. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for oil and natural gas. A costless collar consists of a purchased put option and a sold call option, which establishes a minimum and maximum price, respectively, that the Company will receive for the volumes under the contract.

It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. The Company does not post collateral, nor is it exposed to potential margin calls, under any of these contracts, as they are secured under the Credit Agreement (as defined below) or under unsecured lines of credit with non-bank counterparties. See Note 10 – “Long-Term Debt” for further information regarding the Credit Agreement.

As of September 30, 2021, the Company’s oil derivative contracts include hedges for 0.6 MMBbls of remaining 2021 production with an average floor price of $56.56 per barrel and 1.9 MMBbls of 2022 production with an average floor price of $53.39 per barrel. As of September 30, 2021, the Company’s natural gas derivative contracts include 4.4 Bcf of remaining 2021 production with an average floor price of $2.90 per MMBtu and 16.3 Bcf of 2022 production with an average floor price of $2.78 per MMBtu. Approximately 95% of the Company’s hedges are swaps, and the Company has no three-way collars or short puts.

As of September 30, 2021, the following financial derivative instruments were in place (fair value in thousands):


Commodity	Period	Derivative	Volume/Quarter		Weighted Average Price/Unit		Fair Value
Oil	Q4 2021	Swap	547,251	Bbls	$	57.06 (1)	(9,535)
Oil	Q1 2022	Swap	585,000	Bbls	$	56.34 (1)	(9,628)
Oil	Q2 2022	Swap	473,000	Bbls	$	52.92 (1)	(8,551)
Oil	Q3 2022	Swap	417,000	Bbls	$	51.27 (1)	(7,426)
Oil	Q4 2022	Swap	407,000	Bbls	$	51.86 (1)	(6,363)
Oil	Q1 2023	Swap	380,000	Bbls	$	53.15 (1)	(4,837)
Oil	Q2 2023	Swap	150,000	Bbls	$	58.43 (1)	(987)
Oil	Q4 2021	Collar	60,251	Bbls	$	52.00 – 58.80 (1)	(955)
Natural Gas	Q4 2021	Swap	3,975,000	MMBtus	$	2.89 (2)	(11,948)


Commodity	Period	Derivative	Volume/Quarter		Weighted Average Price/Unit		Fair Value
Natural Gas	Q1 2022	Swap	3,990,000	MMBtus	$	2.78 (2)	(12,222)
Natural Gas	Q2 2022	Swap	4,375,000	MMBtus	$	2.77 (2)	(4,886)
Natural Gas	Q3 2022	Swap	3,650,000	MMBtus	$	2.73 (2)	(4,244)
Natural Gas	Q4 2022	Swap	3,800,000	MMBtus	$	2.57 (2)	(4,508)
Natural Gas	Q1 2023	Swap	2,850,000	MMBtus	$	2.73 (2)	(3,902)
Natural Gas	Q2 2023	Swap	3,000,000	MMBtus	$	2.73 (2)	(1,315)
Natural Gas	Q4 2021	Collar	400,000	MMBtus	$	3.00 – 3.41 (2)	(1,022)
Natural Gas	Q1 2022	Collar	510,000	MMBtus	$	3.00 – 3.41 (2)	(1,284)
Natural Gas	Q1 2023	Collar	550,000	MMBtus	$	2.63 – 3.01 (2)	(556)

		Total net fair value of derivative instruments (in thousands)					$(94,169)

(1)	Based on West Texas Intermediate oil prices.

(2)	Based on Henry Hub NYMEX natural gas prices.

The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of September 30, 2021 (in thousands):


	Gross			Netting (1)		Total
Assets	$	—		$	—	$	—
Liabilities	$	(94,169	)	$	—	$	(94,169	)

(1)	Represents counterparty netting under agreements governing such derivatives.

The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2020 (in thousands):


	Gross			Netting (1)		Total
Assets	$	3,493		$	—	$	3,493
Liabilities	$	(2,965	)	$	—	$	(2,965	)

(1)	Represents counterparty netting under agreements governing such derivatives.

The following table summarizes the effect of derivative contracts on the consolidated statements of operations for the three and nine months ended September 30, 2021 and 2020 (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
Oil contracts	$	(8,512	)	$	3,959		$	(16,186	)	$	15,217
Natural gas contracts		(4,378	)		1,709			(5,525	)		7,154

Realized gain (loss)	$	(12,890	)	$	5,668		$	(21,711	)	$	22,371

Oil contracts	$	(3,069	)	$	(6,329	)	$	(51,994	)	$	17,840
Natural gas contracts		(32,431	)		(6,708	)		(44,246	)		(9,685	)

Non-cash mark-to-market gain (loss)	$	(35,500	)	$	(13,037	)	$	(96,240	)	$	8,155

Gain (loss) on derivatives, net	$	(48,390	)	$	(7,369	)	$	(117,951	)	$	30,526

6.	Stock-Based Compensation

2009 Incentive Compensation Plan

The Company has in place the Contango Oil & Gas Company Third Amended and Restated 2009 Incentive Compensation Plan (the “2009 Plan”) which allows for stock options, restricted stock or performance stock units to be awarded to executive officers, directors and employees as a performance-based award.

On July 14, 2021, the Company’s board of directors, subject to stockholder approval, approved an amendment to the 2009 Plan that will increase the number of shares of the Company’s common stock authorized for issuance pursuant to the 2009 Plan by 11,500,000 from 12,500,000 shares to 24,000,000 shares, effective immediately following the closing of the Pending Independence Merger.

Restricted Stock

During the nine months ended September 30, 2021, the Company granted 1,415,189 shares of restricted common stock to employees, which vest ratably over three years, under the 2009 Plan, as part of their overall compensation package. Additionally, during the nine months ended September 30, 2021, the Company issued 54,825 restricted stock awards to the members of the board of directors in lieu of cash fees earned during the fourth quarter of 2020 and first quarter of 2021, which vested immediately. The Company also granted 80,142 shares of restricted common stock related to internal reorganizational changes during the nine months ended September 30, 2021. The weighted average fair value of the restricted shares granted during the nine months ended September 30, 2021, was $3.72 per share, with a total fair value of approximately $5.8 million and no adjustment for an estimated weighted average forfeiture rate. There were 62,306 forfeitures of restricted stock during the nine months ended September 30, 2021. The aggregate intrinsic value of restricted shares forfeited during the nine months ended September 30, 2021 was approximately $0.2 million. The Company recognized approximately $2.2 million in restricted stock compensation expense during the nine months ended September 30, 2021, related to restricted stock previously granted to its officers, employees and directors. As of September 30, 2021, the number of shares of unvested restricted common stock outstanding was 2,039,165 shares, with an additional $5.7 million of future restricted stock compensation expense remaining to be recognized over the weighted average vesting period of 2.4 years. Approximately 3.0 million shares remained available for grant under the 2009 Plan as of September 30, 2021, assuming PSUs (as defined below) are settled at 100% of target. In October 2021, the Company granted 162,726 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan as a result of their re-election to the board at the annual shareholders’ meeting.

During the nine months ended September 30, 2020, the Company granted 1,041,365 shares of restricted common stock to employees, which vest ratably over three years, under the 2009 Plan, as part of their overall compensation package and 152,248 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan. The weighted average fair value of the restricted shares granted during the nine months ended September 30, 2020, was $2.26 per share, with a total fair value of approximately $2.7 million and no adjustment for an estimated weighted average forfeiture rate. There were 32,205 forfeitures of restricted stock during the nine months ended September 30, 2020. The aggregate intrinsic value of restricted shares forfeited during the nine months ended September 30, 2020 was approximately $0.1 million. The Company recognized approximately $0.8 million in restricted stock compensation expense during the nine months ended September 30, 2020, related to restricted stock previously granted to its officers, employees and directors.

Per the agreement for the Pending Independence Merger, all unvested restricted stock awards held by Contango employees, executives and directors will vest on the closing date of the Pending Independence Merger. As of November 10, 2021, the number of shares of unvested restricted common stock outstanding was 2,201,891 shares.

Performance Stock Units

Compensation expense associated with PSUs is based on the grant date fair value of a single PSU as determined using the Monte Carlo simulation model, which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As it is intended that the PSUs will be settled with shares of the Company’s common stock after three years, the PSU awards are accounted for as equity awards, and the fair value is calculated on the grant date. The simulation model calculates the payout percentage based on the stock price performance over the performance period. The concluded fair value is based on the average achievement percentage over all the iterations. The resulting fair value expense is amortized over the life of the PSU award.

The Company granted 1,772,066 PSUs under the 2009 Plan to its executive officers and certain employees as part of their overall compensation package during the nine months ended September 30, 2021. The performance period will be measured between May 1, 2021 and April 30, 2024. These PSU awards were valued at a weighted average fair value of $8.25 per unit. There were 16,334 forfeitures of PSUs during the nine months ended September 30, 2021. The Company recognized approximately $5.9 million in stock compensation expense related to previously granted PSUs during the nine months ended September 30, 2021. As of September 30, 2021, the number of unvested PSU grants outstanding was 4,718,977, assuming settlement at the target threshold of 100%, with an additional $20.4 million of future compensation expense related to PSUs remaining to be recognized over the weighted average vesting period of 2.2 years.

The Company granted 2,846,140 PSUs to its executive officers and certain employees as part of their overall compensation package during the nine months ended September 30, 2020. The performance period will be measured between May 1, 2020 and April 30, 2023. These PSU awards were valued at a weighted average fair value of $4.90 per unit. No PSUs were forfeited during the nine months ended September 30, 2020. The Company recognized approximately $1.6 million in stock compensation expense related to previously granted PSUs during the nine months ended September 30, 2020.

Per the agreement for the Pending Independence Merger, all unvested PSUs held by Contango employees and executives will vest on the closing date of the Pending Independence Merger, at the maximum payout percentage (for then current employees assuming sufficient shares then available under the 2009 Plan to settle such awards). As of November 10, 2021, the number of unvested PSU grants was 4,718,977, assuming settlement at the target threshold of 100%. The maximum payout on these PSUs is 300% of target, or 14,156,931 shares of common stock.

Stock Options

Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the nine months ended September 30, 2021 and 2020, there was no excess tax benefit recognized.

Compensation expense related to stock option grants is recognized over the stock option’s vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model. No stock options were granted or exercised during the nine months ended September 30, 2021 or 2020.

During the nine months ended September 30, 2021, no stock options were forfeited by former employees, and 19,268 stock options expired. During the nine months ended September 30, 2020, no stock options were forfeited by former employees, and 869 stock options expired. As of September 30, 2021, there were 579 stock options vested and exercisable. The exercise price for such options ranges from $35.00 to $38.98 per share, with an average remaining contractual life of 0.4 years. All outstanding stock options were granted under the Company’s 2005 Stock Incentive Plan.

Per the agreement for the Pending Independence Merger, all stock options held by Contango employees and executives will vest and be deemed exercised on the closing date of the Pending Independence Merger; however, stock options with an exercise price per share that equals or exceeds the fair market value of a share of common stock will be cancelled for no consideration on the closing date of the Pending Independence Merger. As of November 10, 2021, there were 579 stock options vested and exercisable with price ranges between $35.00 and $38.98 per share.

7.	Leases

During the nine months ended September 30, 2021, the Company acquired several contracts in the Mid-Con Acquisition and the Silvertip Acquisition related to compressors, vehicle leases and office space with terms of twelve months or more, which qualify as operating or finance leases. The number of contracts the Company acquired in the Wind River Basin Acquisition which qualified as operating or finance leases were minimal, as most contracts were month-to-month or less than twelve months. The Company also entered into new contracts related to office space, IT equipment and compressors during the nine months ended September 30, 2021. As of September 30, 2021, the Company’s operating leases included compressors and office space, and the Company’s finance leases included vehicles, compressors and office equipment.

The Company also has compressor contracts which are on a month-to-month basis, and while it is probable the contracts will be renewed on a monthly basis, the compressors can be easily substituted or cancelled by either party, with minimal penalties. Leases with these terms are not included on the Company’s balance sheet and are recognized on the consolidated statements of operations on a straight-line basis over the lease term.

The following table summarizes the balance sheet information related to the Company’s leases as of September 30, 2021 and December 31, 2020 (in thousands):


	September 30, 2021			December 31, 2020
Operating lease right of use asset (1)	$	2,853		$	2,452
Operating lease liability - current (2)	$	(2,041	)	$	(1,832	)
Operating lease liability - long-term (3)		(775	)		(522	)

Total operating lease liability	$	(2,816	)	$	(2,354	)

Financing lease right of use asset (1)	$	4,284		$	2,996
Financing lease liability - current (2)	$	(1,480	)	$	(940	)
Financing lease liability - long-term (3)		(2,898	)		(2,102	)

Total financing lease liability	$	(4,378	)	$	(3,042	)

(1)	Included in “Right-of-use lease assets” on the consolidated balance sheets.

(2)	Included in “Accounts payable and accrued liabilities” on the consolidated balance sheets.

(3)	Included in “Lease liabilities” on the consolidated balance sheets.

The Company’s leases generally do not provide an implicit rate, and therefore, the Company uses its incremental borrowing rate as the discount rate when measuring operating and financing lease liabilities. The incremental borrowing rate represents an estimate of the interest rate the Company would incur at lease commencement to borrow an amount equal to the lease payments on a collateralized basis over the term of a lease.

The table below presents the weighted average remaining lease terms and weighted average discount rates for the Company’s leases as of September 30, 2021 and December 31, 2020:


	September 30, 2021			December 31, 2020
Weighted Average Remaining Lease Terms (in years):
Operating leases		1.55			1.47
Financing leases		3.22			3.24
Weighted Average Discount Rate:
Operating leases		6.02	%		5.72	%
Financing leases		5.82	%		5.92	%

Maturities for the Company’s lease liabilities on the consolidated balance sheet as of September 30, 2021, were as follows (in thousands):


	September 30, 2021
	Operating Leases			Financing Leases
2021 (remaining after September 30, 2021)	$	2,147		$	1,641
2022		547			1,509
2023		182			1,184
2024		45			447
2025		18			17
2026		29			—

Total future minimum lease payments		2,968			4,798
Less: imputed interest		(152	)		(420	)

Present value of lease liabilities	$	2,816		$	4,378

The following table summarizes expenses related to the Company’s leases for the three months ended September 30, 2021 and 2020 (in thousands):


	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
Operating lease cost (1) (2)	$	775	$	843
Financing lease cost - amortization of right-of-use assets		350		197
Financing lease cost - interest on lease liabilities		62		39
Administrative lease cost (3)		5		19
Short-term lease cost (1) (4)		341		562

Total lease cost	$	1,533	$	1,660

(1)	This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners.

(2)	Costs related to office leases and compressors with lease terms of twelve months or more.

(3)	Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year.

(4)	Costs related primarily to generators and compressor agreements with lease terms of more than one month and less than one year.

The following table summarizes expenses related to the Company’s leases for the nine months ended September 30, 2021 and 2020 (in thousands):


	Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
Operating lease cost (1) (2)	$	2,674	$	2,212
Financing lease cost - amortization of right-of-use assets		927		450
Financing lease cost - interest on lease liabilities		173		88
Administrative lease cost (3)		41		56
Short-term lease cost (1) (4)		1,132		1,614

Total lease cost	$	4,947	$	4,420

(1)	This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners.

(2)	Costs related to office leases and compressors with lease terms of twelve months or more.

(3)	Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year.

(4)	Costs related primarily to generators and compressor agreements with lease terms of more than one month and less than one year.

During the nine months ended September 30, 2021, there were $2.7 million and $1.2 million in cash payments related to the Company’s operating leases and financing leases, respectively. During the nine months ended September 30, 2020, there were $2.4 million and $0.6 million in cash payments related to the Company’s operating leases and financing leases, respectively.

8.	Other Financial Information

The following table provides additional detail for accounts receivable, prepaid expenses and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands):


	September 30, 2021			December 31, 2020
Accounts receivable:
Trade receivables (1)	$	73,719		$	20,306
Receivable for Alta Resources distribution		1,712			1,712
Joint interest billings (1)		27,868			15,637
Income taxes receivable		—			268
Other receivables		242			2,209
Allowance for doubtful accounts		(2,270	)		(2,270	)

Total accounts receivable	$	101,271		$	37,862

Prepaid expenses:
Prepaid insurance	$	4,859		$	2,825
Other (2)		1,942			535

Total prepaid expenses	$	6,801		$	3,360

Accounts payable and accrued liabilities (1):
Royalties and revenue payable	$	44,858		$	23,701
Legal suspense related to revenues (3)		30,760			27,983
Advances from partners (4)		7,290			76
Accrued exploration and development (4)		17,739			490
Trade payables		41,150			14,273
Accrued general and administrative expenses (5)		10,700			6,191
Accrued operating expenses		12,520			5,755
Accrued operating and finance leases		3,521			2,772
Other accounts payable and accrued liabilities		5,070			2,729

Total accounts payable and accrued liabilities	$	173,608		$	83,970

(1)	Increase in 2021 primarily due to the Mid-Con Acquisition, the Silvertip Acquisition and the Wind River Basin Acquisition.

(2)	Other prepaids primarily includes software licenses and the implementation costs related to a cloud computing arrangement for the Company’s accounting system.

(3)	Suspended revenues primarily relate to amounts for which there is some question as to valid ownership, unknown addresses of payees or some other payment dispute.

(4)	Increase primarily related to the Company’s resumed drilling program in the second quarter of 2021 in the NE Bullseye area in the Permian region.

(5)	The September 30, 2021 balance includes an accrual of $2.8 million for a legal judgment that was paid in October 2021. See Note 12 – “Commitments and Contingencies” for more information.

Included in the table below are supplemental cash flow disclosures and non-cash investing activities during the nine months ended September 30, 2021 and 2020 (in thousands):


	Nine Months Ended September 30,
	2021		2020
Cash payments:
Interest payments	$	2,767	$	2,991
Income tax payments	$	1,332	$	233
Non-cash investing activities in the consolidated statements of cash flows:
Increase (decrease) in accrued capital expenditures	$	17,249	$	(7,113	)

The Company issued a total of 25,552,933 shares of Contango common stock at the closing of the Mid-Con Acquisition. See Note 3 – “Acquisitions and Dispositions” for more information.

9. Investment in Exaro Energy III LLC

The Company maintains an ownership interest in Exaro of approximately 37%. The Company’s share in the equity of Exaro at September 30, 2021 was approximately $4.9 million. The Company accounts for its ownership in Exaro using the equity method of accounting, and therefore, does not include its share of individual operating results, production or reserves in those reported for the Company’s consolidated results.

The Company’s share in Exaro’s results of operations recognized for the three and nine months ended September 30, 2021 was a loss of $1.1 million, net of no tax expense and a loss of $1.9 million, net of no tax expense, respectively. The Company’s share in Exaro’s results of operations recognized for the three and nine months ended September 30, 2020 was a loss of $0.1 million, net of no tax expense, and a loss of $13 thousand, net of no tax expense, respectively.

10. Long-Term Debt

Credit Agreement

On September 17, 2019, the Company entered into its new revolving credit agreement with JPMorgan Chase Bank and other lenders (as amended, the “Credit Agreement”), which established a borrowing base of $65 million. The Credit Agreement matures on September 17, 2024. The borrowing base is subject to semi-annual redeterminations which will occur on or around May 1st and November 1st of each year.

On October 30, 2020, the Company entered into the Third Amendment to the Credit Agreement, which became effective on January 21, 2021, upon the satisfaction of certain conditions, including the consummation of the Mid-Con Acquisition. See Note 3 – “Acquisitions and Dispositions” for more information. The Third Amendment provided for, among other things, (i) a 25 basis point increase in the applicable margin at each level of the borrowing base utilization-based pricing grid, (ii) an increase of the borrowing base from $75.0 million to $130.0 million on the effective date of the Third Amendment, with a $10.0 million automatic stepdown in the borrowing base on March 31, 2021, (iii) certain modifications to the Company’s minimum hedging covenant including requiring hedging for at least 75% of the Company’s projected PDP volumes for 24 full calendar months on or prior to 30 days after the effective date of the Third Amendment and on April 1 and October 1 of each calendar year and (iv) the addition of three new banks to the lender group. The Company’s borrowing base was decreased to $120.0 million on March 31, 2021, per the Third Amendment. On January 21, 2021, the Company entered into the Fourth Amendment to the Credit Agreement, which was related to the transfer of a letter of credit for Mid-Con. On May 3, 2021, the Company entered into the Fifth Amendment to the Credit Agreement, which increased the borrowing base from $120.0 million to $250.0 million and expanded the bank group from nine to eleven banks, effective May 3, 2021. The Fifth Amendment also provided for, among other things, (i) the reinstatement of the minimum current ratio covenant calculation of 1.0:1.0 beginning as of June 30, 2021, (ii) a decrease in the maximum Total Debt/EBITDAX leverage ratio calculation from 3.5:1.0 to 3.25:1.0, and (iii) a decrease in the Company’s minimum hedging covenant resulting in requiring hedging for at least 70% of the Company’s projected PDP volumes for 12 full calendar months from the date of delivery of each reserve report and at least 50% of the Company’s projected PDP volumes for months 13 through 24 from the date of delivery of each reserve report and other minor changes which are more administrative in nature.

In light of the Pending Independence Merger, on October 28, 2021, the Company, JPMorgan Chase Bank, N.A (the “Administrative Agent”) and the lenders under the Credit Agreement entered into a waiver letter which, among other things, (i) waives the Company’s obligation under its Credit Agreement to deliver the reserve report otherwise due in October 2021 and (ii) postpones the November 2021 scheduled redetermination of the Company’s borrowing base until on or about February 1, 2022, subject to the Company providing the Administrative Agent by December 31, 2021 with a reserve report evaluating the Company’s proved reserves as of December 1, 2021.

As of September 30, 2021, under the Credit Agreement, the Company had $118.0 million borrowings outstanding, $2.9 million in outstanding letters of credit and borrowing availability of approximately $129.1 million. As of December 31, 2020, the Company had approximately $9.0 million outstanding under the Credit Agreement, $1.9 million in an outstanding letter of credit and borrowing availability of approximately $64.1 million.

The Company initially incurred $1.8 million of arrangement and upfront fees in connection with the Credit Agreement. The Company has incurred an additional $4.2 million in fees for amendments to the Credit Agreement, of which $2.5 million in fees were incurred in 2021 in relation to the Third Amendment and Fifth Amendment. These fees are to be amortized over the remaining term of the Credit Agreement. During the nine months ended September 30, 2021, the Company amortized debt issuance costs of $0.7 million related to the Credit Agreement. As of September 30, 2021, the remaining amortizable balance of these fees was $3.6 million and will be amortized through September 17, 2024.

Total interest expense under the Company’s Credit Agreement, including commitment fees, was approximately $1.2 million and $3.2 million for the three and nine months ended September 30, 2021, respectively. Total interest expense under the Company’s Credit Agreement, including commitment fees, was approximately $1.1 million and $4.4 million, for the three and nine months ended September 30, 2020, respectively. Included in the 2020 interest expense is $1.0 million in debt issuance costs which originally were to be amortized over the life of the loan, but were immediately expensed due to a reduction in the borrowing base under the Second Amendment.

The weighted average interest rates in effect at September 30, 2021 and December 31, 2020 were 3.5% and 2.9%, respectively.

The Credit Agreement contains customary and typical restrictive covenants. The Fifth Amendment requires a Current Ratio of greater than or equal to 1.0:1.0 and a Leverage Ratio of less than or equal to 3.25:1.0. The Credit Agreement also contains typical events of default that may accelerate repayment of any borrowings and/or termination of the facility. Events of default include, but are not limited to, a going concern qualification, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events. As of September 30, 2021, the Company was in compliance with all of its covenants under the Credit Agreement.

Paycheck Protection Program Loan

On April 10, 2020, the Company entered into a promissory note evidencing an unsecured loan in the amount of approximately $3.4 million (the “PPP Loan”) made to the Company under the Paycheck Protection Program (the “PPP”). The PPP was established under the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”), signed into law on March 27, 2020, and administered by the U.S. Small Business Administration. The PPP Loan to the Company was made through JPMorgan Chase Bank, N.A and is included in “Long-term debt” on the Company’s consolidated balance sheet as of December 31, 2020.

The PPP Loan was set to mature on the two-year anniversary of the funding date and bears interest at a fixed rate of 1.00% per annum. Monthly principal and interest payments, less the amount of any potential forgiveness (discussed below), commenced after the six-month anniversary of the funding date. The promissory note evidencing the PPP Loan provided for customary events of default, including, among others, those relating to failure to make payment, bankruptcy, breaches of representations and material adverse effects.

The Company utilized the PPP Loan amount for qualifying expenses during the 24-week coverage period, and on July 12, 2021, submitted its updated application for forgiveness of the total amount outstanding under the PPP Loan in accordance with the updated application terms of the CARES Act and related guidance. On August 6, 2021, the Company received notice from the Small Business Administration that the PPP loan was forgiven in its entirety. For the three and nine months ended September 30, 2021, the Company recorded other income of $3.4 million for the PPP loan forgiveness within “Gain on extinguishment of debt” on its consolidated statements of operations.

11. Income Taxes

The Company’s income tax provision (benefit) for continuing operations consists of the following (in thousands):


	Three Months Ended September 30,					Nine Months Ended September 30,
	2021			2020		2021			2020
Current tax provision (benefit)
Federal	$	(1,384	)	$	—	$	(1,638	)	$	274
State		318			369		927			481

Total	$	(1,066	)	$	369	$	(711	)	$	755

Deferred tax provision:
Federal	$	—		$	—	$	—		$	—
State		—			299		—			676

Total	$	—		$	299	$	—		$	676

Total tax provision (benefit)
Federal	$	(1,384	)	$	—	$	(1,638	)	$	274
State		318			668		927			1,157

Total income tax provision (benefit):	$	(1,066	)	$	668	$	(711	)	$	1,431

State income tax expense relates to income taxes for the quarter which are expected to be owed primarily to the states of Louisiana and Oklahoma resulting from activities within those states and, in each case, that are not shielded by existing Federal tax attributes. The Federal income tax benefit for the nine months ended September 30, 2021 results from applying the estimated annual effective tax rate to the year-to-date pre-tax loss, less amounts recorded in the first and second quarters of 2021, plus a small true-up of a previously recorded alternative minimum tax refund was reflected.

As of September 30, 2021, the Company had federal net operating loss (“NOL”) carryforwards of approximately $404.7 million and state NOL carryforwards of $26.4 million. The Federal NOL carryforwards are made up of: (i) those acquired in the merger with Crimson Exploration, Inc. in 2013 and (ii) from subsequent taxable losses during the years 2014 through 2020, due to lower commodity prices and utilization of various elections available to the Company in expensing capital expenditures incurred in the development of oil and natural gas properties. Generally, these NOLs are available to reduce future taxable income and the related income tax liability subject to the limitations set forth in Internal Revenue Code Section 382 related to changes of more than 50% of ownership of the Company’s stock by 5% or greater shareholders over a three-year period (a Section 382 Ownership Change) from the time of such an ownership change. The Company experienced two separate Section 382 Ownership Changes in connection with two of its equity offerings occurring in 2018 and 2019, respectively (the “Ownership Changes”). Market conditions at the time of the 2019 Ownership Change had diminished from the time of the 2018 Ownership Change, thus subjecting virtually all of the Company’s tax attributes to an annual limitation of $0.7 million a year (in pre-tax dollars). This lower annual limitation resulting from the 2019 Ownership Change effectively eliminates the ability to utilize these tax attributes in the future. As a result of the Ownership Changes, the Company has recorded a valuation allowance against substantially all of its NOLs and other deferred tax assets. The Company determined that no Section 382 Ownership Change from share activity occurred in the nine months ended September 30, 2021. The valuation allowance balances at September 30, 2021 for federal and state purposes are approximately $150.6 million and approximately $3.1 million, respectively.

The Consolidated Appropriations Act of 2021 was signed into law on December 27, 2020 to provide a response by the Federal government to the pandemic and contains numerous tax incentives and extensions for businesses. One such provision is a change in the deductibility of expenses for meals purchased from a restaurant, where, in calendar years 2021 and 2022, there is no reduction in deductibility (compared to a prior 50% limitation). For the nine months ended September 30, 2021, the Company is claiming a 100% benefit for qualifying meal expenses.

12. Commitments and Contingencies

Legal Proceedings

In January 2016, the Company was named as the defendant in a lawsuit filed in the District Court for Harris County in Texas by a third-party operator. The Company participated in the drilling of a well in 2012, which experienced serious difficulties during the initial drilling, which eventually led to the plugging and abandoning of the wellbore prior to reaching the target depth. In dispute is whether the Company is responsible for the additional costs related to the drilling difficulties and plugging and abandonment. In September 2019, the case went to trial, and the court ruled in favor of the plaintiff. Prior to the judgment, the Company had approximately $1.1 million in accounts payable related to the disputed costs associated with this case. As a result of the judgment, during the three months ended September 30, 2019, the Company recorded an additional $2.1 million liability for the judgment plus fees and interest. The Company filed an appeal with the appellate court for a review of the initial trial court’s decision. On January 23, 2021, the appellate court notified both parties that it would begin reviewing the merits of the case beginning on February 23, 2021. On March 3, 2021, the appellate court affirmed the trial court’s decision. The Company filed a petition with the Texas Supreme Court requesting a review of the appellate court’s decision, and on September 24, 2021, the Texas Supreme Court notified both parties that it would not be reviewing the case. As a result, during the three months ended September 30, 2021, the Company recorded an additional $0.7 million liability for the final judgment plus interest. The total judgment, interest and fees of $3.9 million were paid in October 2021.

13. Subsequent Events

On November 3, 2021, the Company filed and mailed its definitive proxy statement for the Special Meeting of the Stockholders of the Company in connection with the Pending Independence Merger. The Special Meeting of the Stockholders to vote on the approval of the Pending Independence Merger has been scheduled for December 6, 2021

Exhibit 99.5

Report of independent auditors

The Board of Directors

Liberty Energy, LLC

We have audited the accompanying financial statements of Liberty Energy, LLC, which comprise the balance sheet as of December 31, 2019, and the related statements of operations and comprehensive loss, owner’s equity, and cash flows for the year then ended, and the related notes to the financial statements.

Management’s responsibility for the financial statements

Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Auditor’s responsibility

Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Liberty Energy, LLC at December 31, 2019, and the results of its operations and its cash flows for the year then ended in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

March 31, 2021

Liberty Energy, LLC

Balance sheet

December 31, 2019


Assets
Current assets:
Cash and cash equivalents	$	34,714,201
Accounts receivable from oil and gas sales		44,632,447
Prepaid drilling costs		117,963,195
Other current assets		406,783

Total current assets		197,716,626
Oil and gas properties:
Proved wells and related equipment and facilities		2,205,826,488
Unproved properties		90,712,252
Support equipment and facilities		22,026,064

		2,318,564,804
Less: Accumulated depreciation, depletion, amortization and impairment		(1,221,268,319	)

Oil and gas properties, net		1,097,296,485
Other assets		699,666

Total assets	$	1,295,712,777

Liabilities and owner’s equity
Current liabilities:
Income tax payable	$	213,977
Accounts payable and accrued expenses		9,165,646
Accrued expenses, affiliates		1,619,857
Current portion of asset retirement obligation		2,754,358

Total current liabilities		13,753,838
Long-term liabilities:
Asset retirement obligation		12,633,024

Total liabilities		26,386,862
Owner’s equity:
Initial capital		1,000
Additional paid-in capital		2,364,898,688
Accumulated deficit		(1,095,573,773	)

Total owner’s equity		1,269,325,915
Total liabilities and owner’s equity	$	1,295,712,777

Liberty Energy, LLC

Statement of operations and comprehensive loss

year ended December 31, 2019


Revenues:
Oil, gas and other sales	$	320,312,573
Other income		2,236,437

Total revenues, net		322,549,010
Operating expenses:
Production		130,978,954
Exploration		623,432
Depreciation, depletion, amortization and accretion		168,235,389
Impairment of assets		20,599,477
General and administrative		885,407

Total operating expenses		321,322,659
Gain on sale of assets		834,305
Gain on settlement of asset retirement obligations		589,192

Total operating income		2,649,848
Other expense:
Investment management fees and expenses		(4,921,657	)

Other expense		(4,921,657	)

Loss before income taxes		(2,271,809	)
Income tax expense		801,379

Total comprehensive loss	$	(3,073,188	)

Liberty Energy, LLC

Statement of owner’s equity

year ended December 31, 2019


	Initial Capital		Additional Paid-In Capital		Accumulated Deficit			Total Owner’s Equity
Balance at January 1, 2019	$	1,000	$	2,266,724,421	$	(1,092,500,585	)	$	1,174,224,836
Capital contributions		—		98,174,267		—			98,174,267
Net loss		—		—		(3,073,188	)		(3,073,188	)

Balance at December 31, 2019	$	1,000	$	2,364,898,688	$	(1,095,573,773	)	$	1,269,325,915

Liberty Energy, LLC

Statement of cash flows

year ended December 31, 2019


Operating activities
Net loss	$	(3,073,188	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Gain on sale of assets		(834,305	)
Gain on settlement of asset retirement obligations		(589,192	)
Depreciation, depletion, amortization and accretion expense		168,235,389
Impairment of assets		20,599,477
Change in accounts receivable		3,204,726
Change in income tax receivable		(308,996	)
Change in accounts payable and accrued expenses		4,836,151
Change in other assets		(1,763,541	)

Net cash provided by operating activities		190,306,521
Investing activities
Proceeds from the sales of working interests and other equipment		32,861,508
Investment in oil and gas properties		(327,435,204	)

Net cash used in investing activities		(294,573,696	)
Financing activities
Capital contributions from parent		98,174,267

Net cash provided by financing activities		98,174,267

Decrease in cash and cash equivalents		(6,092,908	)
Cash and cash equivalents at beginning of year		40,807,109

Cash and cash equivalents at end of year	$	34,714,201

Supplemental disclosure
Development of oil and natural gas properties – changes in related accruals	$	49,981,864
Taxes paid		465,558

Liberty Energy, LLC

Notes to financial statements

December 31, 2019

1.	Organization and operations

•

Liberty Energy, LLC (LEC) (the Company) is an oil and gas asset acquisition company and one of the LLC subsidiaries owned by Liberty Energy Holdings, LLC (LEH). LEH is wholly owned by Liberty Mutual Insurance Company (Liberty Mutual). The primary objective of LEC is to make investments in the upstream and midstream oil and gas sectors. The Company owns direct working interests (nonoperating) in oil and gas projects which is focused on the upstream and midstream energy sector. LEC’s investments are located exclusively in the United States.

•

Liberty Mutual has committed to fund cash requirements for property acquisitions, exploration and development, other oil and gas investments, and operations of the Company. Capital contributions pursuant to such commitments were approximately $98.2 million in 2019. As of December 31, 2019, Liberty Mutual has additionally committed up to $23.2 million to the Company for its cash requirements.

2.	Summary of significant accounting policies

Basis of presentation and consolidation principles

•

The accompanying financial statements present the accounts of the Company and have been prepared in conformity with U.S. generally accepted accounting principles (GAAP). All material intercompany transactions and balances have been eliminated in consolidation.

•

The Company also owns undivided interests in producing and non-producing oil and gas wells. Ownership of these assets is structured as an undivided interest, not as ownership in a limited partnership, a limited liability company or other form of entity. Each owner is proportionately responsible for each well-level liability and individually entitled to the benefits produced by the asset. The Company proportionately consolidates its undivided interests in oil and gas wells.

Use of estimates

•

Financial statements prepared in accordance with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and the disclosure of contingent assets and liabilities, as of the balance sheet date and the reported amounts of revenues and expenses during the reporting period reflected. Management evaluates its estimates and related assumptions regularly, including those related to proved reserves, the value of properties and equipment asset retirement obligations, litigation liabilities, income taxes and fair value changes. While the amounts included in the financial statements reflect management’s best estimates and assumptions, changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from those estimates.

Cash and cash equivalents

•

Cash and equivalents are short-term, highly liquid investments that are both readily convertible into known amounts of cash and so near to maturity that they present insignificant risk of changes in value due to changing interest rates.

Revenue recognition

•

The Company accounts for oil and gas sales from its interests in producing wells under the sales method. The sales method requires that the Company recognize revenue based on the amount of oil and gas sold to purchasers on its behalf, which may be different from the Company’s entitled production based on its interest in the properties.

Accounts receivable from oil and gas sales

•

Accounts receivable are stated at cost less allowance for doubtful accounts for potentially uncollectible amounts.

Prepaid drilling costs

•

Prepaid drilling costs represent future lease acquisition costs, tangible drilling costs, and intangible drilling costs that have been paid in advance to operators and are stated at cost.

Oil and gas properties

•

Oil and gas properties are accounted for using the successful efforts method whereby only costs (including lease acquisition and intangible drilling costs) associated with exploration efforts that result in the discovery of proved reserves are capitalized. Costs of acquiring and exploring unproved oil and gas leases are initially capitalized pending the results of exploration activities. When exploration projects do not yield proved reserves, the costs of the unsuccessful wells and associated lease acquisition costs are expensed. Geological and geophysical expenditures are expensed as incurred. All development costs are capitalized. See Note 3 for additional information on oil and gas properties held at December 31, 2019.

Depreciation, depletion, amortization and accretion

•

Capitalized costs of producing oil and gas properties are depreciated and depleted on a field-by-field basis. The Company uses the unit-of-production method to deplete its properties and the calculation is based on units of proved developed reserves as estimated by independent petroleum engineers. Significant processing and pipeline assets are depreciated over a fixed period using the straight-line method. In periods subsequent to the initial measurement of an asset retirement obligation at present value, a period-to-period increase in the carrying amount of the liability is recognized as accretion expense, which represents the effect of the passage of time on the amount of the liability. An equivalent amount is added to the carrying amount of the liability.

Gains or losses on the sale of assets

•

Gains or losses are recognized when oil and gas properties are sold. The sale of a partial interest in an exploratory oil and gas property is recognized as a recovery of cost and serves to reduce the basis of the property. A gain from the sale of a partial interest in an exploratory oil and gas property is recognized only in the event that the proceeds exceed the carrying value of the portion of the property sold.

Impairments of oil and gas properties

•

The Company is required to review its oil and gas properties when facts and circumstances indicate the possible existence of impairment. The Company tests for recoverability by comparing the undiscounted cash flows expected to be generated by a project to the property’s carrying value. When a property’s carrying value is greater than the expected future cash flows, impairment expense is recognized to the extent that the carrying value of the property exceeds its discounted expected cash flows.

•

In employing the discounted cash flow method described above, key inputs include commodity prices, locational basis difference, production, project development costs and the discount rate which are based on management’s expectations about outcomes with respect to these variables. Specifically, the Company uses a Wood Mackenzie curve and applies a discount rate to the projected future cash flows. Impairment is assessed on a field-by-field basis. See Note 4 for additional information on impairments recognized for the year ended December 31, 2019.

Asset retirement obligations

•

The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred if a reasonable estimate of fair value can be made. Asset retirement costs are capitalized when they are incurred as part of the carrying amount of the oil and gas properties and are subsequently depleted using the unit-of-production method. The asset retirement obligation is accreted over the estimated useful life of the associated asset until settlement. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized if it is material. The asset retirement obligation recorded by the Company relates primarily to the plugging, dismantlement and site restoration of oil and gas wells. Please refer to Note 5 for further information on the Company’s asset retirement obligations.

Investment management fees and expenses

•

In 2012, LEH entered into an Investment Advisory Agreement (Agreement) with Liberty Mutual Investment (LMI) to manage the assets of the Company’s investment portfolios. The agreement provided for management fees to be paid to LMI, which is allocated to the respective wholly owned subsidiaries of LEH based on their respective assets. LEC was allocated management fees totaling $4.9 million in 2019. Management fees are presented as other expense in the statement of operations. Please see Note 8 for additional information on the management fees recognized for the year ended December 31, 2019.

Income taxes

•

LEC is a single-member limited liability company and is treated as a disregarded entity for U.S. Federal income tax purposes. Accordingly, LEC is considered part of Liberty Mutual’s Federal income tax reporting and does not file a separate U.S. Federal income tax return. Similarly, LEC is reported as a part of Liberty Mutual Insurance Company for state income tax reporting, with the exception of those activities in Texas, which taxes limited liability companies as separate legal entities. Accordingly, LEC provides for Texas margins tax and other state income taxes withheld from partnership investments. In accordance with Accounting Standards Codification (ASC) 740, Income Taxes, interest or penalties related to the Company operations, if any, are analyzed and recorded by Liberty Mutual in its consolidated financial statements.

•

Please see Note 9 for additional information on the income tax expense recognized for the year ended December 31, 2019.

Distributions and returns of capital

•

The Company determines the character of all repatriations made to Liberty Mutual on a monthly basis. Repatriations are designated as being from earnings to the extent of the existence of distributable retained earnings during the month in which the distribution is made. Repatriations in excess of distributable retained earnings are designated as returns of capital. The Company will recognize a deficit to the extent by which cumulative distributions exceed retained earnings.

Recently adopted accounting standards

•

Effective January 1, 2019, the Company adopted Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers. ASU 2014-09 was issued to clarify the principles for recognizing revenue, however, financial instrument transactions are not within the scope of this guidance. ASU 2014-09 is effective for nonpublic business entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. As of December 31, 2019, the Company has adopted the standard and the adoption did not have an impact the Company’s financial statements.

•

Effective January 1, 2019, the Company adopted the Financial Accounting Standards (FASB) issued ASU 2016-02, Leases. The amendments required a lessee to recognize a right-of-use asset and a lease liability on the balance sheet for leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the statements of income. The amendments of ASU 2016-02 were effective for public business entities for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The Company’s adoption of the standard did not have a material impact the Company’s financial statements.

Future adoption of new accounting standards

•

The Company will adopt the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. ASU 2016-13 replaces the current incurred loss model with an expected credit loss model, which measures credit losses on financial instruments measured at amortized cost and will require companies to recognize an allowance for expected credit losses. In addition, ASU 2016-13 also amends the credit loss measurement guidance for available-for-sale debt securities and beneficial interests in securitized financial assets. This amendment removes certain factors to consider when determining whether credit losses should be recognized and will require companies to recognize expected credit losses through an allowance. ASU 2016-13 is effective for public business entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The adoption is not expected to have a material impact on the Company’s financial statements.

•

There are no other accounting standards not yet adopted by the Company that are expected to have a material impact on its financial position or results of operations.

3.	Oil and gas properties

•

LEC owns direct working interests in various oil and gas properties and applies the successful efforts method of accounting. At December 31, 2019, the DJ Basin properties and Reeves properties constituted the largest components of oil and gas properties and represent 62% and 24% of the portfolio, respectively.

4.	Impairments

•

In 2019, the Company recognized impairment expense of $20.6 million related to oil and gas properties.

5.	Asset retirement obligations

•

The Company accounts for obligations arising from the retirement of tangible long-lived assets in accordance with ASC 410, Asset Retirement and Environmental Obligations. The Company’s asset retirement obligations represent future abandonment costs of tangible assets such as platforms, wells and other facilities. ASC 410 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost is capitalized as part of the carrying value of the long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is charged to depletion over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized if it is material.

•

As of December 31, 2019, the estimated fair value of the Company’s asset retirement obligation was $15.4 million.

6.	Accounts receivable

•

As of December 31, 2019, the Company had an accounts receivable balance of $44.6 million related entirely to oil and gas sales from joint venture operators. The Company’s debtors are primarily entities that operate exclusively in the oil and gas sector, therefore, the collectability of LEC’s receivables are highly dependent on general economic conditions that are beyond its control. As of December 31, 2019, the Company has deemed its accounts receivable to be collectible and did not record an allowance for doubtful accounts.

7.	Fair value measurement

Other financial instruments

•

The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, prepaid insurance, accounts payable and accrued liabilities. The carrying value of the current assets (cash and cash equivalents, accounts receivable, etc.) and current liabilities (accounts payable and accrued liabilities) approximate their fair value due to the short maturity of these items.

8.	Transactions with affiliates

•

In 2012, LEH contracted with LMI in order to provide the services necessary to execute the mission of the Company. Under the terms of the Agreement, LEH pays LMI a monthly management fee of 0.3% of the average U.S. GAAP carrying value of LEH’ s assets under management. In return for this payment, LMI provides investment management services to LEH and its wholly owned subsidiaries such that the Company may execute its business objectives. LEC recognized $4.9 million of expense related to this arrangement in 2019. At December 31, 2019, LEC had $830 thousand of investment management fees and $790 thousand for state income taxes totaling $1.6 million recorded in accrued expenses, affiliates.

9.	Income taxes

•

The Company recognized income tax expense of $801 thousand in 2019. This differs from the amounts computed by applying the U.S. Federal income tax rate of 21% to income or loss before provision for income taxes as follows:


Expected income tax expense (benefit)	$	(477,080	)
Disregarded entity income		477,080

Federal income tax expense		—
State tax expense		801,379

Income tax expense	$	801,379

•

The allocation of income tax expense between current and deferred is as follows:


Current income tax expense (benefit):
U.S. Federal	$	—
State		801,379

Total current tax (benefit)		801,379
Deferred income tax expense:
U.S. Federal		—

Total U.S. Federal, foreign and state income tax expense	$	801,379

•

There are no deferred tax assets or liabilities as of December 31, 2019.

•

As of December 31, 2019, the Company has no unrecognized tax benefits. The Company does not expect any material changes to the balance of unrecognized tax benefits within the next twelve months.

•

The Company recognizes interest and penalties related to unrecognized tax benefits in U.S. Federal income tax expense. During the year ended December 31, 2019, the Company did not recognize any interest or penalties.

•

The Texas statute of limitations has expired through the 2014 tax year. Any adjustments that may result from the examinations of these income tax returns are not expected to have a material impact on the financial position, liquidity, or results of operations of the Company.

10.

Commitments

•

Pursuant to the terms of the respective subscription agreements, as of December 31, 2019, the Company is committed to make capital contributions in the amount of $23.2 million. Liberty Mutual has committed to fund LEC in order to enable the Company to settle these obligations.

11.

Divestitures

•

In August 2019, the Company sold its interest in certain oil and gas properties in Dimmit, Zavala and Frio Counties, Texas, to unrelated third parties for $7.8 million, net of customary closing adjustments. A net gain of $0.9 million was recognized on the sale.

•

In August 2019, the Company sold its interest in certain oil and gas properties in Gonzalez, Texas to an unrelated third party for $5.1 million, net of customary closing adjustments. A net loss of $11.0 million was recognized on the sale.

•

In September 2019, the Company sold its interest in certain oil and gas properties in Garfield County, Colorado to an unrelated third party for $17.1 million, net of customary closing adjustments. A net gain of $10.8 million was recognized on the sale.

12.

Subsequent events

•

The Company has assessed material subsequent events through March 31, 2021, the date the financial statements were available to be issued.

Dispositions

•

In February 2020, the Company sold its non-operated interest in Ward County to an unrelated third party for $.6 million. A net gain of $.5 million was recognized on the sale.

Impairments

•

On July 19, 2020, the Company entered into an agreement with an investment firm, whereby both parties contributed various energy assets into a new joint venture vehicle. The Company contributed its entire interest in LEC to the joint venture in exchange for a minority interest in the new entity. As a result of being held for sale, a $231 million impairment is reflected in the statements of income as of June 30, 2020.

COVID-19

•

In December 2019, a novel coronavirus commonly referred to as “COVID-19” surfaced in Wuhan, China. The outbreak has since spread to other countries, including the United States, and efforts to contain the spread of this coronavirus have intensified and are ongoing. The outbreak and any preventative or protective actions that governments, other third parties or we may take in respect of the coronavirus may result in a continued period of business disruption and reduced operations. The extent to which the coronavirus impacts our future results will depend on developments which are highly uncertain and cannot be predicted, including litigation developments, legislative or regulatory actions and intervention, the length and severity of the coronavirus (including of second waves) and the actions of government actors to contain the coronavirus or treat its impact, among others. Possible effects on our business and operations also include disruptions to business operations. A significant rise in the number of COVID-19 infections, infections in a wide range of countries and regions, or a prolongation of the outbreak, could create an adverse economic effect on the Company.

Liberty Energy, LLC

Supplemental oil and gas information (unaudited)

December 31, 2019

Estimated quantities of proved oil and natural gas reserves – unaudited

•

The reserves presented below summarize the net ownership interests in estimated quantities of proved and proved developed oil and natural gas reserves of the properties at December 31, 2019, estimated in accordance with SEC guidelines, based on a report of Netherland, Sewell & Associates, Inc., the Company’s independent reserves engineer, and the related summary of changes in estimated quantities of net remaining proved reserves during the year.

•

Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs) existing at the time the estimate was made. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made.

•

The following table sets forth information for the year ended December 31, 2019, with respect to changes in the proved reserves:


	Oil (Mbbl)			Gas (MMcf)			Liquids (Mbbl)			MBOE
January 1, 2019		47,938			573,522			45,138			188,663

Revisions		(15,760	)		(138,973	)		(18,327	)		(57,249	)
Extensions		2,639			64,941			2,271			15,734
Divestiture of reserves		(2,271	)		(73,295	)		(2,078	)		(16,564	)
Production		(3,501	)		(38,357	)		(2,021	)		(11,914	)

December 31, 2019		29,045			387,838			24,984			118,669

Proved developed reserve, at January 1, 2019		13,161			235,012			14,583			66,912
Proved developed reserves at December 31, 2019		11,688			187,372			11,799			54,716
Proved undeveloped reserves at January 1, 2019		34,777			338,509			30,555			121,750
Proved undeveloped reserves at December 31, 2019		17,357			200,466			13,185			63,953

•

During the year ended December 31, 2019, the Company’s extensions and discoveries of 15,731 MBOE resulted primarily from the drilling of 22 new wells and from 77 new proved undeveloped locations added. The Partnership’s negative revisions of previous estimated quantities of 57,249 MBOE were due mainly to 238 proved undeveloped locations being removed due to economics. The divestures of 16,754 MBOE was mainly comprised of divesting our properties in the Piceance Basin of Colorado.

Standardized measure of discounted future net cash flows relating to proved oil and gas reserves – unaudited

•

The following tables set forth the computation of the standardized measure of discounted future net cash flows (the “Standardized Measure”) relating to proved reserves and the changes in such cash flows of the Acquired Properties in accordance with the FASB’s authoritative guidance related to disclosures about oil and gas producing activities. The Standardized Measure is the estimated net future cash inflows from proved reserves less estimated future production and development costs, estimated plugging and abandonment costs and a discount factor. Production costs do not include depreciation, depletion and amortization of capitalized acquisition, exploration and development costs. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month average oil and natural gas index, calculated as the unweighted arithmetic average of the first day of the month price for each month during the year, as prescribed by ASC 932.

•

Estimated future production costs related to period-end reserves are based on period-end costs. Such costs include, but are not limited to, production taxes and direct operating costs. Inflation and other anticipatory costs are not considered until the actual cost change takes effect. In accordance with the FASB’s authoritative guidance, a discount rate of 10% is applied to the annual future net cash flows.

•

The average prices (adjusted for basis and quality differentials) related to proved reserves at December 31, 2019 for natural gas ($ per Mcf) were $0.923, for oil ($ per Bbl) were $17.05 and for NGLs ($ per Bbl) were $49.27. Future cash inflows were reduced by estimated future development, and production costs based on year-end costs resulting in net cash flow before tax. Federal income taxes have not been deducted from future production revenues in the calculation of the Standardized Measure as the Company is a pass-through entity for United States income tax purposes and each member is separately taxed on their share of the properties’ taxable income. In addition, Texas margin taxes have not been deducted from future production revenues in the calculation of the Standardized Measure as the impact of these taxes would not have a significant effect on the calculated Standardized Measure.

•

The Standardized Measure is not intended to be representative of the fair market value of the proved reserves. The calculations of revenues and costs do not necessarily represent the amounts to be received or expended. Accordingly, the estimates of future net cash flows from proved reserves and the present value thereof may not be materially correct when judged against actual subsequent results. Further, since prices and costs do not remain static, and no price or cost changes have been considered, and future production and development costs are estimates to be incurred in developing and producing the estimated proved oil and natural gas reserves, the results are not necessarily indicative of the fair market value of estimated proved reserves, and the results may not be comparable to estimates disclosed by other oil and natural gas producers.

•

The following summary sets forth the future net cash flows related to proved oil and gas reserves based on the standardized measure prescribed in ASC 932 (in thousands):


Future crude oil, natural gas and NGL sales	$	2,214,936
Future production costs		(759,218	)
Future development costs		(433,339	)
Future income tax expense		(5,596	)

Future net cash flows		1,016,782
10% annual discount		(398,850	)

Standardized measure of discounted future net cash flows	$	617,932

•

The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands):


Balance at beginning of period	$	1,031,183
Net change in prices and production costs		(382,358	)
Net change in future development costs		163,807
Oil and gas net revenue		(170,636	)
Extensions		49,976
Divestiture of reserves		(65,055	)
Revisions of previous quantity estimates		(211,601	)
Previously estimated development costs incurred		134,267
Net change in taxes		1,456
Accretion of discount		103,577
Changes in timing and other		(36,684	)

End of year	$	617,932

Exhibit 99.7

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

Defined terms included below shall have the same meaning as terms defined and included within the proxy statement/prospectus (File No. 333-258157), dated November 3, 2021 (the “Proxy Statement/Prospectus”).

On December 7, 2021 (the “Closing Date”), Crescent Energy Company (formerly known as IE PubCo Inc., “Crescent” or the “Company”), Contango, Independence, OpCo and certain entities formed by the Company (C Merger Sub and L Merger Sub) completed the transactions contemplated by the Transaction Agreement dated June 7, 2021 pursuant to which, (1) OpCo was recapitalized such that after giving effect to such recapitalization, all of the equity interest in OpCo consisting of 127,536,463 OpCo Units (the “OpCo Recapitalization”), Independence distributed all of the OpCo Units held by it, and all of the shares of Crescent Class B Common Stock held by it to the members of Independence in accordance with its organizational documents (the “Distribution”), and immediately following the Distribution, Independence merged with and into OpCo with OpCo surviving (the “Independence Merger”), (2) immediately following the Independence Merger, C Merger Sub merged with and into Contango, with Contango surviving the merger as a direct wholly owned corporate subsidiary of the Company (the “Contango Merger”), (3) as a result of the Contango Merger, each outstanding share of Contango Common Stock was converted into the right to receive a number of shares of Crescent Class A Common Stock equal to the Exchange Ratio, (4) immediately following the Contango Merger, Contango merged with and into L Merger Sub, with L Merger Sub surviving the merger as a direct wholly owned limited liability company subsidiary of the Company (the “LLC Merger”), (5) immediately following the LLC Merger, the Company contributed 100% of the equity interests in L Merger Sub to OpCo in exchange for certain Opco Units (the “Contribution”), and (6) immediately following the Contribution, OpCo contributed L Merger Sub to Energy Finance. Each of these transactions contemplated by the Transaction Agreement and completed on the Closing Date is collectively referred to hereafter as the “Transactions.” Subject to the terms and conditions within the Transaction Agreement, holders of eligible shares of Contango Common Stock received 0.20 shares of Crescent Class A common stock in exchange for each share of Contango Common Stock held.

The following unaudited pro forma condensed combined financial statements (the “pro forma financial statements”) have been prepared from the respective historical consolidated financial statements of Contango and Independence, adjusted to give effect to the Transactions. Additionally, the pro forma financial statements include adjustments associated with the Independence Transactions, which were completed by Independence prior to the Closing Date. Further, Contango completed the Mid-Con Acquisition and the Grizzly Acquisition (collectively, the “Contango Transactions”) during the periods presented.

The unaudited pro forma condensed combined statements of operations (the “pro forma statements of operations”) for the nine months ended September 30, 2021 and for the year ended December 31, 2020 give effect to each of the Transactions, the Independence Transactions, and the Contango Transactions (collectively, the “Pro Forma Transactions”) as if they had been consummated on January 1, 2020. The unaudited pro forma condensed combined balance sheet (the “pro forma balance sheet”) gives effect to the Pro Forma Transactions as if they had occurred on September 30, 2021. The pro forma balance sheet as of September 30, 2021 reflects no impact from the Independence Transactions and the Contango Transactions, as they are already reflected in the historical balance sheets of Independence and Contango, respectively. Additionally, the pro forma statement of operations for the nine months ended September 30, 2021 reflects no impact from the Titan Acquisition as it is already reflected in the historical statement of operations of Independence. The pro forma financial statements contain certain reclassification adjustments to conform the historical Contango financial statement presentation to Independence’s financial statement presentation.

The following pro forma financial statements are based on, and should be read in conjunction with:

•

the historical audited combined and consolidated financial statements of Independence for the year ended December 31, 2020 and the unaudited condensed combined and consolidated financial statements of Independence as of and for the nine months ended September 30, 2021, and the related notes thereto, attached as Exhibits 99.1 and 99.2 hereto;

•

the historical audited consolidated financial statements of Contango for the year ended December 31, 2020 and the unaudited consolidated financial statements of Contango as of and for the nine months ended September 30, 2021, and the related notes thereto, attached as Exhibits 99.3 and 99.4 hereto;

•

the historical audited consolidated financial statements of Liberty for the year ended December 31, 2019 and the unaudited consolidated financial statements of Liberty as of and for the six months ended June 30, 2020, and the related notes thereto, attached as Exhibits 99.5 and 99.6 hereto;

•

the “Management’s discussion and analysis of financial condition and results of operations” included in the Proxy Statement/Prospectus; and

•

the “Risk factors” and other cautionary statements included within the Proxy Statement/Prospectus.

The accompanying pro forma financial statements were derived by making certain transaction adjustments to the historical financial statements noted above. The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual impact of the Pro Forma Transactions may differ from the adjustments made to the pro forma financial statements. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects for the periods presented as if the Pro Forma Transactions had been consummated earlier, and that all adjustments necessary to present fairly the pro forma financial statements have been made.

As of the date of this current report on Form 8-K/A, the Company has not completed the detailed valuation study necessary to arrive at the required final estimates of the fair value of the assets to be acquired and the liabilities to be assumed and the related allocations of purchase price, nor has it identified all adjustments necessary to conform Contango’s accounting policies to the Company’s accounting policies. A final determination of the fair value of Contango’s assets and liabilities will be based on the actual assets and liabilities of Contango that existed as of the Closing Date and will be finalized before the end of the measurement period.

In addition, the value of the consideration to be paid by the Company upon the consummation of the Transactions was determined based on the closing price of Contango’s common stock on the Closing Date. The pro forma adjustments are preliminary and are subject to change as additional information becomes available and as additional analysis is performed. The preliminary pro forma adjustments have been made solely for the purpose of providing the unaudited pro forma financial statements presented below. The Company estimated the fair value of Contango’s assets and liabilities based on discussions with Contango’s management, preliminary valuation studies, due diligence, and information presented in Contango’s SEC filings. Any increases or decreases in the fair value of assets acquired and liabilities assumed upon completion of the final valuations will result in adjustments to the pro forma balance sheet and/or pro forma statements of operations. The final purchase price allocation may be materially different than that reflected in the pro forma purchase price allocation presented herein.

The pro forma financial statements and related notes are presented for illustrative purposes only and should not be relied upon as an indication of the financial condition or the operating results that the Company would have achieved if the Transaction Agreement had been entered into and the Pro Forma Transactions had taken place on the assumed dates. The pro forma financial statements do not reflect future events that may occur after the consummation of the Transactions, including, but not limited to, the anticipated realization of ongoing savings from potential operating efficiencies, asset dispositions, cost savings, or economies of scale that the Company may achieve with respect to the combined operations. As a result, future results may vary significantly from the results reflected in the pro forma financial statements and should not be relied on as an indication of the future results of the Company.

Unaudited pro forma condensed combined balance sheet

as of September 30, 2021

(in thousands, except share data)


	Independence (Historical)			Contango (Historical)			Reclassifications			Transaction Adjustments			Pro Forma Combined
CURRENT ASSETS:
Cash and cash equivalents	$	63,541		$	3,084		$	—		$	—		$	66,625
Accounts receivable, net		172,446			101,271			—			—			273,717
Accounts receivable - affiliates		5,423			—			—			—			5,423
Drilling advances		6,212			—			—			—			6,212
Prepaid expenses		—			6,801			(6,801	) (a)		—			—
Inventory		—			571			(571	) (a)		—			—
Prepaid and other assets		7,683			—			7,372	(a)		—			15,055

Total current assets		255,305			111,727			—			—			367,032
PROPERTY, PLANT AND EQUIPMENT:
Oil and natural gas properties, successful efforts method of accounting:
Proved properties		4,876,998			1,610,533			—			(510,526	) (b)		5,977,005
Unproved properties		312,784			14,146			—			(13,671	) (b)		313,259
Other property & equipment		135,383			2,855			—			(1,270	) (b)		136,968
Accumulated depreciation, depletion, amortization and impairment		(1,863,981	)		(1,183,606	)		—			1,183,606	(b)		(1,863,981	)

Total property, plant and equipment, net		3,461,184			443,928			—			658,139			4,563,251
OTHER NON-CURRENT ASSETS:
Investments in affiliates		—			4,896			—			—			4,896
Goodwill		—			—			—			106,523	(c)		106,523
Right-of-use lease assets		—			7,137			—			(3,464	) (d)		3,673
Debt issuance costs		—			3,582			(3,582	) (a)		—			—
Deposits		—			1,813			(1,813	) (a)		—			—
Other assets		21,339			—			5,395	(a)		(3,582	) (e)		23,152

Total other non-current assets		21,339			17,428			—			99,477			138,244

TOTAL ASSETS	$	3,737,828		$	573,083		$	—		$	757,616		$	5,068,527

CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	160,265		$	173,608		$	—		$	25,392	(f)	$	359,265
Accounts payable – affiliates		3,942			—			—			—			3,942
Current derivative liability		345,553			71,702			—			—			417,255
Current asset retirement obligations		—			5,193			—			—			5,193
Other current liabilities		3,726			—			—			—			3,726

Total current liabilities		513,486			250,503			—			25,392			789,381
NON-CURRENT LIABILITIES:
Long-term debt		765,531			118,000			—			—	(e)		883,531
Long-term derivative liability		145,601			22,467			—			—			168,068
Asset retirement obligations		106,489			126,076			—			—			232,565
Lease liabilities		—			3,673			—			—	(d)		3,673
Deferred tax liabilities		—			—			—			145,812	(g)		145,812
Other liabilities		27,798			—			—			—			27,798

Total non-current liabilities		1,045,419			270,216			—			145,812			1,461,447

TOTAL LIABILITIES		1,558,905			520,719			—			171,204			2,250,828

COMMITMENTS AND CONTINGENCIES
REDEEMABLE NONCONTROLLING INTERESTS		—			—			—			2,204,773	(i)		2,204,773
SHAREHOLDERS’ EQUITY:
Members’ equity		2,165,256			—			—			(9,269	) (f)		—
											(2,155,987	) (h)
Contango common stock, $0.04 par value, 400,000,000 shares authorized, 201,435,797 shares issued and 201,175,841 shares outstanding at September 30, 2021		—			8,045			—			(8,045	) (h)		—
Crescent Class A common stock, $0.0001 par value, 1,000,000,000 shares authorized and 43,099,100 shares issued and outstanding at September 30, 2021 on a pro forma basis		—			—			—			4	(i)		4
Crescent Class B common stock, $0.0001 par value, 500,000,000 shares authorized and 127,536,463 shares issued and outstanding at September 30, 2021 on a pro forma basis		—			—			—			13	(i)		13


	Independence (Historical)		Contango (Historical)			Reclassifications		Transaction Adjustments					Pro Forma Combined
Crescent preferred stock, $0.0001 par value, 500,000,000 shares authorized and 1,000 Series I preferred shares issued and outstanding at September 30, 2021 on a pro forma basis		—		—			—		—		(i	)		—
Additional paid-in capital		—		623,796			—		(6,571	)	(g	)		638,521
									(623,796	)	(h	)
									605,813		(i	)
									39,279		(j	)
Treasury shares at cost (259,956 shares at September 30, 2021)		—		(1,024	)		—		1,024		(h	)		—
Accumulated deficit		—		(578,453	)		—		(16,123	)	(f	)		(39,279	)
									594,576		(h	)
									(39,279	)	(j	)
Noncontrolling interests		13,667		—			—		—					13,667

Total shareholders’ equity		2,178,923		52,364			—		(1,618,361	)				612,926

TOTAL LIABILITIES, REEDEMABLE NONCONTROLLING INTERESTS AND SHAREHOLDERS’ EQUITY	$	3,737,828	$	573,083		$	—	$	757,616				$	5,068,527

Unaudited pro forma condensed combined statement of operations

for the nine months ended September 30, 2021

(in thousands, except per share data)


	Independence (Historical)			Independence Transaction Adjustments			Independence As Adjusted			Contango (Historical)			Contango Transaction Adjustments			Contango As Adjusted			Reclassifi cations			Transaction Adjustments			Pro Forma Combined
REVENUES:
Oil and condensate sales	$	627,817		$	(7,564	) (aa)	$	620,253		$	149,246		$	6,957	(ee)	$	156,203		$	—		$	—		$	776,456
Natural gas sales		230,271			(2,292	) (aa)		227,979			55,556			712	(ee)		56,268			—			—			284,247
Natural gas liquids sales		121,613			(1,200	) (aa)		120,413			35,735			743	(ee)		36,478			—			—			156,891
Midstream and other		34,017			(538	) (aa)		33,479			—			42	(ee)		42			2,980	(ff)		—			36,501
Other operating revenues		—			—			—			2,980			—			2,980			(2,980	) (ff)		—			—

Total revenues		1,013,718			(11,594	)		1,002,124			243,517			8,454			251,971			—			—			1,254,095
EXPENSES:
Operating expense		424,427			(5,827	) (aa)		418,600			108,901			3,234	(ee)		112,135			—			—			530,735
Depreciation, depletion and amortization		233,122			(3,478	) (aa)		229,644			30,391			1,413	(ee)		31,804			—			38,838	(gg)		300,285
Impairment and abandonment of oil and natural gas properties		—			—			—			712			—			712			—			—			712
Exploration expense		833			(3	) (aa)		830			458			—			458			—			—			1,288
Midstream operating expense		8,848			(132	) (aa)		8,716			—			—			—			—			—			8,716
General and administrative expense		33,775			(195	) (aa)		33,580			39,441			96	(ee)		39,537			—			10,097	(hh)		95,486
																							12,272	(ii)
(Gain) loss on sale of assets		(9,418	)		—			(9,418	)		—			—			—			(461	) (ff)		—			(9,879	)

Total expenses		691,587			(9,635	)		681,952			179,903			4,743			184,646			(461	)		61,207			927,343

OTHER INCOME (EXPENSE):
Interest expense		(37,810	)		377	(aa)		(43,521	)		(4,156	)		(327	) (ee)		(4,483	)		—			734	(ll)		(47,270	)
					(6,088	) (bb)
(loss) on derivatives		(885,032	)		—			(885,032	)		(117,951	)		(1,597	) (ee)		(119,548	)		—			—			(1,004,580	)
Gain from investment in affiliates, net of income taxes		—			—			—			(1,897	)		—			(1,897	)		—			—			(1,897	)
Gain from sale of assets		—			—			—			461			—			461			(461	) (ff)		—			—
Gain on extinguishment of debt		—			—			—			3,369			—			3,369			—			—			3,369
Other income (expense)		(54	)		(5	) (aa)		(59	)		3,714			—			3,714			—			—			3,655

Total other income (expense)		(922,896	)		(5,716	)		(928,612	)		(116,460	)		(1,924	)		(118,384	)		(461	)		734			(1,046,723	)

NET LOSS BEFORE INCOME TAXES		(600,765	)		(7,675	)		(608,440	)		(52,846	)		1,787			(51,059	)		—			(60,473	)		(719,971	)

Income tax benefit (provision)		(407	)		1	(aa)		(406	)		711			—			711			—			41,554	(mm)		41,859

NET LOSS		(601,172	)		(7,674	)		(608,846	)		(52,135	)		1,787			(50,348	)		—			(18,919	)		(678,112	)

Less: Net (income) loss attributable to noncontrolling interests		15,368			(8,716	) (aa)		4,016			—			—			—			—			527,345	(nn)		531,361
					(2,636	) (cc)

NET LOSS ATTRIBUTABLE TO COMPANY	$	(585,804	)	$	(19,026	)	$	(604,830	)	$	(52,135	)	$	1,787		$	(50,348	)	$	—		$	508,426		$	(146,751	)

NET LOSS PER SHARE/UNIT:
Class A - basic and diluted	$	(477.51	)																						$	(3.40	) (oo)
Class B - basic and diluted	$	—																							$	—	(oo)
Contango common stock - basic and diluted										$	(0.26	)
WEIGHTED AVERAGE COMMON SHARES/UNITS OUTSTANDING:
Class A - basic and diluted		1,227																								43,099	(oo)
Class B - basic and diluted		—																								127,536	(oo)
Contango common stock - basic and diluted											196,867

Unaudited pro forma condensed combined statement of operations

for the year ended December 31, 2020

(in thousands, except for per share data)


	Independence (Historical)			Independence Transaction Adjustments			Independence As Adjusted			Contango (Historical)			Contango Transaction Adjustments			Contango As Adjusted			Reclassifi cations			Transaction Adjustments			Pro Forma Combined
REVENUES:
Oil and condensate sales	$	491,780		$	(16,737	) (aa)	$	529,420		$	62,461		$	80,729	(ee)	$	143,190		$	—		$	—		$	672,610
					54,377	(dd)
Natural gas sales		149,317			(5,171	) (aa)		172,242			31,381			4,665	(ee)		36,046			—			—			208,288
					28,096	(dd)
Natural gas liquids sales		69,902			(2,321	) (aa)		81,430			17,078			5,380	(ee)		22,458			—			—			103,888
					13,849	(dd)
Midstream and other		43,222			(1,542	) (aa)		49,057			—			(1,252	) (ee)		(1,252	)		2,000	(ff)		—			49,805
					7,377	(dd)
Other operating revenues		—			—			—			2,000			—			2,000			(2,000	) (ff)		—			—

Total revenues		754,221			77,928			832,149			112,920			89,522			202,442			—			—			1,034,591
EXPENSES:
Operating expense		481,834			(17,088	) (aa)		529,500			72,847			69,278	(ee)		142,125			—			—			671,625
					64,754	(dd)
Depreciation, depletion and amortization		372,300			(12,952	) (aa)		466,479			30,032			26,984	(ee)		57,016			—			33,149	(gg)		556,644
					107,131	(dd)
Impairment and abandonment of oil and natural gas properties		247,215			(8,945	) (aa)		469,476			168,802			19,647	(ee)		188,449			—			—			657,925
					231,206	(dd)
Exploration expense		486			(14	) (aa)		1,148			11,594			4,290	(ee)		15,884			—			—			17,032
					676	(dd)
Midstream operating expense		9,472			(380	) (aa)		9,092			—			—			—			—			—			9,092
General and administrative expense		16,542			(40	) (aa)		17,033			24,940			8,620	(ee)		33,560			—			13,463	(hh)		145,089
					531	(dd)																	16,362	(ii)
																							39,279	(jj)
																							25,392	(kk)
(Gain) loss on sale of assets		—			652	(dd)		652			—			—			—			(4,501	) (ff)		—			(3,849	)

Total expenses		1,127,849			365,531			1,493,380			308,215			128,819			437,034			(4,501	)		127,645			2,053,558

OTHER INCOME (EXPENSE):
Interest expense		(38,107	)		1,493	(aa)		(53,750	)		(5,022	)		(5,137	) (ee)		(10,159	)		—			562	(ll)		(63,347	)
					(17,136	) (bb)
Gain (loss) on derivatives		195,284			—			195,284			27,585			16,036	(ee)		43,621			—			—			238,905
Gain from investment in affiliates, net of income taxes		—			—			—			27			—			27			—			—			27
Gain from sale of assets		—			—			—			4,501			—			4,501			(4,501	) (ff)		—			—
Other income (expense)		341			(16	) (aa)		(1,802	)		3,609			(38	) (ee)		3,571			—			—			1,769
					(2,127	) (dd)

Total other income (expense)		157,518			(17,786	)		139,732			30,700			10,861			41,561			(4,501	)		562			177,354

NET LOSS BEFORE INCOME TAXES		(216,110	)		(305,389	)		(521,499	)		(164,595	)		(28,436	)		(193,031	)		—			(127,083	)		(841,613	)
Income tax benefit (provision)		(14	)		1	(aa)		(35	)		(747	)		—			(747	)		—			42,965	(mm)		42,183
					(22	) (dd)

NET LOSS		(216,124	)		(305,410	)		(521,534	)		(165,342	)		(28,436	)		(193,778	)		—			(84,118	)		(799,430	)
Less: Net (income) loss attributable to noncontrolling interests		97,475			(7,495	) (aa)		207			—			—			—			—			619,406	(nn)		619,613
					(89,773	) (cc)

NET LOSS ATTRIBUTABLE TO COMPANY	$	(118,649	)	$	(402,678	)	$	(521,327	)	$	(165,342	)	$	(28,436	)	$	(193,778	)	$	—		$	535,288		$	(179,817	)

NET LOSS PER SHARE/UNIT:
Class A - basic and diluted	$	(153.30	)																						$	(4.17	) (oo)
Class B - basic and diluted	$	—																							$	—	(oo)
Contango common stock - basic and diluted										$	(1.20	)
WEIGHTED AVERAGE COMMON SHARES/UNITS OUTSTANDING:
Class A - basic and diluted		774																								43,099	(oo)
Class B - basic and diluted		—																								127,536	(oo)
Contango common stock - basic and diluted											137,522

Notes to unaudited pro forma condensed combined financial statements

NOTE 1 – Basis of pro forma presentation

The pro forma financial statements have been derived from the historical financial statements of Contango and Independence. Certain of Contango’s historical amounts have been reclassified to conform to Independence’s financial statement presentation. The pro forma balance sheet as of September 30, 2021 gives effect to the Transactions as if they had occurred on September 30, 2021. The pro forma statements of operations for the nine months ended September 30, 2021 and for the year ended December 31, 2020 give effect to the Pro Forma Transactions as if they had occurred on January 1, 2020.

The pro forma financial statements reflect pro forma adjustments that are based on available information and certain assumptions that management believes are reasonable. However, actual results may differ from those reflected in these statements. In management’s opinion, all adjustments known to date that are necessary to present fairly the pro forma information have been made. The pro forma financial statements do not purport to represent what the combined entity’s financial position or results of operations would have been if the Pro Forma Transactions had actually occurred on the dates indicated above, nor are they indicative of the Company’s future financial position or results of operations.

These pro forma financial statements should be read in conjunction with the historical financial statements, and related notes thereto, of Contango and Independence for the periods presented.

NOTE 2 – Preliminary acquisition accounting

The Transactions will be accounted for using the acquisition method of accounting for business combinations with Independence considered to be the accounting acquirer. The allocation of the preliminary estimated purchase price for Contango is based upon management’s estimates of and assumptions related to the fair value of assets to be acquired and liabilities to be assumed as of September 30, 2021 using currently available information. Because the pro forma financial statements have been prepared based on these preliminary estimates, the final purchase price allocation and the resulting effect on the Company’s financial position and results of operations may differ significantly from the pro forma amounts included in this exhibit to the current report on Form 8-K/A. The Company expects to finalize its allocation of the purchase price as soon as practicable.

The preliminary purchase price allocation is subject to change as a result of several factors, including but not limited to:

•

changes in the estimated fair value of Contango’s assets acquired and liabilities assumed as of the Closing Date;

•

the tax basis of Contango’s assets and liabilities as of the Closing Date; and

•

certain of the factors described in “Risk Factors” included within the Proxy Statement/Prospectus.

The preliminary determination of consideration transferred, fair value of assets acquired and liabilities assumed that are expected to be recorded are as follows (in thousands, except exchange ratio, share, and per share data):


Consideration transferred:
Shares of Contango common stock outstanding		199,136,676
NYSE American closing price per share on December 7, 2021	$	3.22

Fair value of Contango common stock		641,220

Settlement of Restricted Stock Awards		7,090
Settlement of PSU Awards		6,306
Company Stock Option Awards		—

Consideration transferred	$	654,616

Fair value of assets acquired:
Cash	$	3,084
Accounts receivable		101,271


Other current assets		7,372
Proved oil and natural gas properties		1,100,007
Unproven oil and natural gas properties		475
Other property, plant and equipment		1,585
Goodwill		106,523
Other noncurrent assets		10,382

Total assets acquired		1,330,699
Fair value of liabilities assumed:
Accounts payable and accrued expenses		189,731
Derivative liabilities		94,169
Long-term debt		118,000
Deferred tax liabilities, net		139,241
Asset retirement obligation		131,269
Other liabilities		3,673

Total liabilities assumed		676,083

Assets acquired and liabilities assumed	$	654,616

Under the Transaction Agreement, Contango stockholders received 0.20 shares of Crescent Class A Common Stock for each share of Contango Common Stock issued and outstanding immediately prior to the Closing Date. This resulted in the Company issuing approximately 39.8 million shares of Crescent Class A Common Stock in exchange for 199.1 million outstanding shares of Contango Common Stock and 3.3 million shares of Crescent Class A Common Stock in settlement of Contango’s equity compensation awards, a portion of which will be recognized as expense in the statement of operations for the Company. As Contango Common Stock were listed and actively traded on an exchange as of the Closing Date, the trading price of Contango Common Stock was used to estimate the fair value of consideration transferred for the pro forma financial statements. The Contango Merger is intended to be non-taxable to Contango stockholders and in such case Contango’s tax basis in its assets and liabilities will carry over to the Company.

NOTE 3 – Adjustments to the pro forma financial statements

The pro forma financial statements have been prepared to illustrate the effect of the Pro Forma Transactions and have been prepared for informational purposes only.

The following pro forma financial statements have been prepared in accordance with Article 11 of Regulation S-X as amended by the final rule, Release No. 33-10786 “Amendments to Financial Disclosures about Acquired and Disposed Businesses.” Release No. 33-10786 replaces the existing pro forma adjustment criteria with simplified requirements to depict the accounting for the transaction (“Transaction Accounting Adjustments”) and allows for supplemental disclosure of the reasonably estimable synergies and other transaction effects that have occurred or are reasonably expected to occur (“Management Adjustments”). Management has elected not to disclose Management Adjustments.

The pro forma provision for income taxes does not necessarily reflect the amounts that would have resulted had the combined company filed consolidated income tax returns during the periods presented.

The pro forma net loss per share amounts presented in the pro forma statements of operations are based upon the number of shares of Crescent Class A Common Stock and Crescent Class B Common Stock outstanding, assuming the Pro Forma Transactions occurred on January 1, 2020.

Pro forma balance sheet adjustments

The adjustments included in the pro forma balance sheet as of September 30, 2021 are as follows:

Reclassifications

(a)	The following reclassifications were made to conform Contango’s financial statement presentation to Independence’s financial statement presentation:

•

The reclassification of $6.8 million of Contango’s prepaid expenses to prepaid and other assets;

•

The reclassification of $0.6 million of Contango’s inventory to prepaid and other assets;

•

The reclassification of $3.6 million of Contango’s debt issuance costs to other assets; and

•

The reclassification of $1.8 million of Contango’s deposits to other assets.

Transaction Adjustments

(b)	Reflects a preliminary purchase price allocation adjustment resulting in a $658.1 million increase to Contango’s net book basis of property, plant, and equipment to record it at fair value.

(c)	Reflects preliminary purchase price allocation adjustments to record goodwill related to the acquisition of Contango.

(d)

Reflects preliminary purchase price allocation adjustments related to Contango’s right of use lease asset and lease liability. Note that the Company is an emerging growth company and its predecessor, Independence, has not yet adopted ASU 2016-02. The pro forma financial statements do not reflect an adjustment for Independence’s adoption of ASU 2016-02 as the expected impact of adoption is currently being finalized and is expected to be immaterial to the consolidated financial statements of the Company.

(e)

Reflects a $3.6 million reduction to other assets to remove capitalized debt issuance costs related to Contango’s existing long-term debt. Note that the carrying value of Contango’s long-term debt is considered to approximate fair value due to the short-term nature of interest rates for the revolving credit facility.

(f)

Reflects the impact of one-time, nonrecurring transaction costs of $25.4 million related to the Transactions. These transaction costs are based on preliminary estimates, and the final amounts and the resulting effect on Independence’s financial position may differ significantly. These incremental costs are not yet reflected in the historical September 30, 2021 consolidated balance sheets of Independence and Contango, but are reflected in the pro forma condensed combined balance sheet as an increase to accounts payable and accrued expenses as they will be expensed by Independence and Contango as incurred. These amounts do not include severance payments for restructuring activities that may occur subsequent to the consummation of the Transactions. Such costs will be recorded as an expense in the financial statements of the Company subsequent to the Transactions.

(g)	Reflects pro forma adjustments resulting in a $145.8 million increase to the net deferred tax liability for the Transactions at the estimated statutory tax rate for the combined company.

(h)	Reflects the elimination of historical equity balances of Contango and Independence in accordance with the acquisition method of accounting.

(i)	Reflects the initial capitalization of the Company, including the issuance of Crescent Class A and Class B common stock as a result of the Contango Merger and the Distribution, respectively.

(j)	Reflects the impact of one-time, nonrecurring costs of $39.3 million related to certain change in control payments made to settle Company PSU Awards of Contango that will be expensed by the Company.

The impact of pro forma adjustments on total redeemable noncontrolling interests and total shareholders’ equity are summarized below (in thousands, except share and per share data):


	Estimated Transaction Costs			Tax effects of the Transactions		Elimination of historical equity			Issuance of Crescent Class A and Class B common stock			Settlement of Company PSU Awards		Transaction Adjustments
Redeemable noncontrolling interests	$	—		$	—	$	—		$	2,204,773	(i)	$	—	$	2,204,773

Total redeemable noncontrolling interests	$	—		$	—	$	—		$	2,204,773		$	—	$	2,204,773

Members’ equity	$	(9,269	) (f)	$	—	$	(2,155,987	) (h)	$	—		$	—	$	(2,165,256	)


	Estimated Transaction Costs					Tax effects of the Transactions					Elimination of historical equity					Issuance of Crescent Class A and Class B common stock				Settlement of Company PSU Awards					Transaction Adjustments
Contango Common Stock,		—					—					(8,045	)	(h	)		—				—					(8,045	)
Crescent Class A common stock		—					—					—					4	(i	)		—					4
Crescent Class B common stock		—					—					—					13	(i	)		—					13
Crescent preferred stock		—					—					—					—	(i	)		—					—
Additional paid-in capital		—					(6,571	)	(g	)		(623,796	)	(h	)		605,813	(i	)		39,279		(j	)		14,725
Treasury shares at cost		—					—					1,024		(h	)		—				—					1,024
Accumulated deficit		(16,123	)	(f	)		—					594,576		(h	)		—				(39,279	)	(j	)		539,174
Noncontrolling interests		—					—					—					—				—					—

Total shareholders’ equity	$	(25,392	)			$	(6,571	)			$	(2,192,228	)			$	605,830			$	—				$	(1,618,361	)

Pro forma statements of operations adjustments

The adjustments included in the pro forma statements of operations for the nine months ended September 30, 2021 and for the year ended December 31, 2020 are as follows:

Independence Transaction Adjustments

(aa)	Reflects the impact on the pro forma statements of operations reflect for the Noncontrolling Interest Carve-out, which is summarized below (in thousands):


Noncontrolling Interest Carve-out	Nine Months Ended September 30, 2021			Year Ended December 31, 2020
Oil and condensate sales	$	(7,564	)	$	(16,737	)
Natural gas sales		(2,292	)		(5,171	)
Natural gas liquids sales		(1,200	)		(2,321	)
Midstream and other		(538	)		(1,542	)
Operating expense		(5,827	)		(17,088	)
Depreciation, depletion and amortization		(3,478	)		(12,952	)
Impairment and abandonment of oil and natural gas properties		—			(8,945	)
Exploration expense		(3	)		(14	)
Midstream operating expense		(132	)		(380	)
General and administrative expense		(195	)		(40	)
Interest expense		377			1,493
Gain (loss) on derivatives		10,302			(7,631	)
Other income (expense)		(5	)		(16	)
Income tax provision		1			1

Net income attributable to noncontrolling interests	$	8,716		$	7,495

(bb)	Reflects pro forma adjustments to interest expense related to the Independence Refinancing.

(cc)	Reflects the impact on the pro forma statements of operations for the reclassification from net loss attributable to noncontrolling interests to net loss attributable to members as a result of the Exchanges.

(dd)	Reflects pro forma adjustments for the Titan Acquisition as if it had been consummated on January 1, 2020, which are summarized below (in thousands):


Titan Acquisition	Year Ended December 31, 2020
Oil and condensate sales	$	54,377
Natural gas sales		28,096
Natural gas liquids sales		13,849
Midstream and other		7,377
Operating expense		64,754
Depreciation, depletion and amortization		107,131
Impairment and abandonment of oil and natural gas properties		231,206


Titan Acquisition	Year Ended December 31, 2020
Exploration expense		676
General and administrative expense		531
(Gain) loss on sale of assets		652
Other income (expense)		(2,127	)
Income tax provision		(22	)

Net income (loss)	$	(303,400	)

Contango Transaction Adjustments

(ee)	Reflects adjustments to the pro forma statements of operations for the Mid-Con Acquisition and Grizzly Acquisition consummated by Contango on January 21, 2021 and February 1, 2021, respectively, which are summarized below (in thousands):


Contango Transaction Adjustments	Nine Months Ended September 30, 2021								Year Ended December 31, 2020
	Mid-Con			Grizzly		Total			Mid-Con			Grizzly			Total
Oil and condensate sales	$	2,554		$	4,403	$	6,957		$	38,024		$	42,705		$	80,729
Natural gas sales		48			663		712			877			3,788			4,665
Natural gas liquids sales		—			743		743			—			5,380			5,380
Midstream and other		43			—		43			(1,252	)		—			(1,252	)
Operating expense		1,243			1,991		3,234			28,176			41,102			69,278
Depreciation, depletion and amortization		620			793		1,413			13,867			13,117			26,984
Impairment and abandonment of oil and natural gas properties		—			—		—			19,647			—			19,647
Exploration expense		—			—		—			4,290			—			4,290
General and administrative expense		97			—		97			8,620			—			8,620
Interest expense		(327	)		—		(327	)		(5,137	)		—			(5,137	)
Gain (loss) on derivatives		(1,597	)		—		(1,597	)		16,036			—			16,036
Other income (expense)		—			—		—			(38	)		—			(38	)

Net income (loss)	$	(1,239	)	$	3,026	$	1,787		$	(26,090	)	$	(2,346	)	$	(28,436	)

Reclassifications

(ff)	The following reclassifications were made to conform Contango’s financial statement presentation to Independence’s financial statement presentation:

Pro forma statement of operations for the nine months ended September 30, 2021

•

The reclassification of $3.0 million of Contango’s other operating revenues to midstream and other; and

•

The reclassification of $0.5 million of Contango’s gain from sale of assets within other income (expense) to (gain) loss on sale of assets within operating expenses.

Pro forma statement of operations for the year ended December 31, 2020

•

The reclassification of $2.0 million of Contango’s other operating revenues to midstream and other; and

•

The reclassification of $4.5 million of Contango’s gain from sale of assets within other income (expense) to (gain) loss on sale of assets within operating expenses.

Transaction Adjustments

(gg)	Reflects the pro forma depletion expense calculated in accordance with the successful efforts method of accounting for oil and gas properties, which was based on the preliminary purchase price allocation.

(hh)	Reflects the impact of the Management Compensation pursuant to the Management Agreement executed by and between the Company and Manager entered into as of December 7, 2021 as further described within the current report filed on Form 8-K dated December 7, 2021.

(ii)

Reflects the impact of the Incentive Compensation pursuant to the Management Agreement executed by and between the Company and Manager on December 6, 2021 as further described within the current report filed on Form 8-K dated December 7, 2021. The amount of expense recognized in the pro forma statements of operations represents the Absolute TSR Portion and Relative TSR Portion of the Company’s Target PSUs using accelerated attribution assuming a grant date of January 1, 2020.

(jj)	Reflects the impact of one-time, nonrecurring costs of $39.3 million related to certain change in control payments made to settle Company PSU Awards of Contango that will be expensed by the Company.

(kk)

Reflects the impact of one-time, nonrecurring transaction costs of $25.4 million related to the Transactions, including advisory, legal, regulatory, accounting, valuation, and other professional fees. These transaction costs are based on preliminary estimates, and the final amounts and the resulting effect on the Company’s results of operations may differ significantly. These amounts do not include severance payments for restructuring activities that may occur subsequent to the consummation of the Transactions. Such costs will be recorded as an expense in the financial statements of the Company subsequent to the Transactions.

(ll)	Reflects the impact of the fair value adjustment to Contango’s long-term debt and write-off of debt issuance costs resulting in decreases in interest expense of $0.7 million for the nine months ended September 30, 2021 and $0.6 million for the year ended December 31, 2020.

(mm)

Reflects the income tax effect of the pro forma adjustments presented. The tax rate applied to the pro forma adjustments was the estimated combined statutory rate of 6.0%, after the effect of noncontrolling interests, for the nine months ended September 30, 2021 and for the year ended December 31, 2020. The effective rate of the Company could be significantly different (either higher or lower) depending on post-Closing activities.

(nn)	Reflects the impact of the issuance of Crescent Class A and Class B common stock as a result of the Contango Merger and the Distribution, respectively, on the allocation of net loss attributable to noncontrolling interests and net loss attributable to the Company.

(oo)	Reflects the impact of the recapitalization of the Company as a result of the Pro Forma Transactions on basic and diluted net loss per share.

The computation of the impact of the pro forma adjustments on the Company’s common stock outstanding and basic and diluted net loss per share of common stock is summarized below:


Net loss per share (in thousands, except per share data)	Nine Months Ended September 30, 2021								Year Ended December 31, 2020
	Pro Forma Combined			Crescent Class A			Crescent Class B		Pro Forma Combined			Crescent Class A			Crescent Class B
Numerator:
Pro forma net loss	$	(678,112	)						$	(799,430	)
Less: Pro forma net loss attributable to noncontrolling interests		531,361								619,613

Pro forma net loss attributable to the Company	$	(146,751	)	$	(146,751	)	$	—	$	(179,817	)	$	(179,817	)	$	—

Denominator:
Pro forma weighted-average shares of common stock outstanding – basic and diluted					43,099			127,536					43,099			127,536
Pro forma net loss per share of common stock – basic and diluted				$	(3.40	)	$	—				$	(4.17	)	$	—

NOTE 4 – Supplemental pro forma oil and natural gas reserves information

Oil and natural gas reserves

The following tables present the estimated pro forma combined net proved developed and undeveloped oil, natural gas, and NGLs reserves information as of December 31, 2020, along with a summary of changes in quantities of net remaining proved reserves for the year ended December 31, 2020. The estimates below are in certain instances presented on a “barrels of oil equivalent or “Boe” basis. To determine Boe in the following tables, natural gas is converted to a crude oil equivalent at the ratio of six Mcf of natural gas to one barrel of crude oil equivalent.

The following estimated pro forma oil and natural gas reserves information is not necessarily indicative of the results that might have occurred had the Pro Forma Transactions been completed on January 1, 2020 and is not intended to be a projection of future results. Independence Transaction Adjustments reflect adjustments to oil and natural gas reserves information for the Noncontrolling Interest Carve-out and the Titan Acquisition. Specifically, (i) the Titan Acquisition results in positive reserve additions as of December 31, 2019, with an offsetting decrease to purchases of reserves in place during the year ended December 31, 2020 and (ii) the Noncontrolling Interest Carveout results in negative adjustments as of December 31, 2019 to account for the reduction in reserves that occurred when certain non-controlling interests in our subsidiaries were redeemed in exchange for a proportionate interest in our subsidiaries’ oil and gas properties and associated reserves. In each case these transactions resulted in corresponding adjustments to the Standardized Measure as set forth in tables further below. Contango Transaction Adjustments reflect adjustments to oil and natural gas reserves information for the Mid-Con Acquisition and the Grizzly Acquisition. Each of these adjustments are further discussed within Note 3 – Adjustments to the pro forma financial statements. Future results may vary significantly from the results reflected because of various factors, including those discussed in “Risk Factors” beginning on page 51 of the Proxy Statement/Prospectus.

Because the Titan Acquisition was completed prior to December 31, 2020, the proved reserves attributable to the Titan Acquisition as of December 31, 2020 were prepared by Independence’s reserve engineers. The reports of Independence’s reserve engineers, which include (as applicable) reserve estimates attributable to the properties acquired in the Titan Acquisition, are filed as exhibits to the Registration Statement on Form S-4 filed by the Company on July 26, 2021 and as amended thereafter on September 13, 2021 and October 8, 2021. The proved reserves attributable to the Noncontrolling Interest Carve-out were prepared by Independence’s management team based on an arithmetic calculation that accounted for the proportionate exchange of oil and natural gas interests involved in such transactions.


	Oil and Condensate (MBbls)
	Independence (Historical)			Independence Transaction Adjustments						Independence As Adjusted			Contango (Historical)			Contango Transaction Adjustments			Contango As Adjusted			Pro Forma Combined
				Noncontrolling Interest Carve-out			Titan Acquisition
Proved Developed and Undeveloped Reserves as of:
December 31, 2019		211,533			(8,612	)		29,045			231,966			19,085			47,609			66,694			298,660
Extensions, discoveries, and other additions		4,088			(168	)		—			3,920			2,074			40			2,114			6,034
Sale of reserves in place		—			—			—			—			(142	)		—			(142	)		(142	)
Purchases of reserves in place		22,409			—			(22,409	)		—			—			—			—			—
Revisions of previous estimates		(57,708	)		2,317			(4,743	)		(60,134	)		(6,339	)		(15,671	)		(22,010	)		(82,144	)
Production		(13,132	)		448			(1,893	)		(14,577	)		(1,674	)		(2,259	)		(3,933	)		(18,510	)

December 31, 2020		167,190			(6,015	)		—			161,175			13,004			29,719			42,723			203,898

Proved Developed Reserves as of:
December 31, 2019		103,728			(4,270	)		11,688			111,146			9,819			37,556			47,375			158,521
December 31, 2020		92,024			(3,359	)		—			88,665			7,166			26,127			33,293			121,958
Proved Undeveloped Reserves as of:
December 31, 2019		107,805			(4,342	)		17,357			120,820			9,266			10,053			19,319			140,139
December 31, 2020		75,166			(2,656	)		—			72,510			5,838			3,592			9,430			81,940


	Natural Gas (MMcf)
	Independence (Historical)			Independence Transaction Adjustments						Independence As Adjusted			Contango (Historical)			Contango Transaction Adjustments			Contango As Adjusted			Pro Forma Combined
				Noncontrolling Interest Carve-out			Titan Acquisition
Proved Developed and Undeveloped Reserves as of:
December 31, 2019		1,161,239			(51,330	)		387,838			1,497,747			131,300			43,085			174,385			1,672,132
Extensions, discoveries, and other additions		21,479			(608	)		—			20,871			423			99			522			21,393
Sale of reserves in place		—			—			—			—			(4,754	)		—			(4,754	)		(4,754	)
Purchases of reserves in place		196,840			—			(196,840	)		—			—			—			—			—
Revisions of previous estimates		(478,153	)		21,347			(172,682	)		(629,488	)		(23,520	)		(14,980	)		(38,500	)		(667,988	)
Production		(78,541	)		2,912			(18,316	)		(93,945	)		(18,967	)		(7,516	)		(26,483	)		(120,428	)

December 31, 2020		822,864			(27,679	)		—			795,185			84,482			20,688			105,170			900,355

Proved Developed Reserves as of:
December 31, 2019		870,491			(38,467	)		187,372			1,019,396			122,691			35,964			158,655			1,178,051
December 31, 2020		748,496			(26,491	)		—			722,005			82,788			20,688			103,476			825,481
Proved Undeveloped Reserves as of:
December 31, 2019		290,748			(12,863	)		200,466			478,351			8,609			7,121			15,730			494,081
December 31, 2020		74,368			(1,188	)		—			73,180			1,694			—			1,694			74,874


	NGLs (MBbls)
	Independence (Historical)			Independence Transaction Adjustments						Independence As Adjusted			Contango (Historical)			Contango Transaction Adjustments			Contango As Adjusted			Pro Forma Combined
				Noncontrolling Interest Carve-out			Titan Acquisition
Proved Developed and Undeveloped Reserves as of:
December 31, 2019		61,126			(2,598	)		24,984			83,512			11,764			5,513			17,277			100,789
Extensions, discoveries, and other additions		603			(23	)		—			580			184			16			200			780
Sale of reserves in place		—			—			—			—			(238	)		—			(238	)		(238	)
Purchases of reserves in place		18,952			—			(18,952	)		—			—			—			—			—
Revisions of previous estimates		(20,279	)		844			(4,785	)		(24,220	)		(3,294	)		(2,355	)		(5,649	)		(29,869	)
Production		(5,078	)		176			(1,247	)		(6,149	)		(1,262	)		(408	)		(1,670	)		(7,819	)

December 31, 2020		55,324			(1,601	)		—			53,723			7,154			2,766			9,920			63,643

Proved Developed Reserves as of:
December 31, 2019		48,997			(2,102	)		11,799			58,694			10,484			4,140			14,624			73,318
December 31, 2020		44,307			(1,368	)		—			42,939			6,595			2,766			9,361			52,300
Proved Undeveloped Reserves as of:
December 31, 2019		12,129			(496	)		13,185			24,818			1,280			1,373			2,653			27,471
December 31, 2020		11,017			(233	)		—			10,784			559			—			559			11,343


	Total (Mboe)
	Independence (Historical)			Independence Transaction Adjustments						Independence As Adjusted			Contango (Historical)			Contango Transaction Adjustments			Contango As Adjusted			Pro Forma Combined
				Noncontrolling Interest Carve-out			Titan Acquisition
Proved Developed and Undeveloped Reserves as of:
December 31, 2019		466,199			(19,765	)		118,669			565,103			52,731			60,303			113,034			678,137
Extensions, discoveries, and other additions		8,271			(293	)		—			7,978			2,328			72			2,400			10,378
Sale of reserves in place		—			—			—			—			(1,172	)		—			(1,172	)		(1,172	)
Purchases of reserves in place		74,168			—			(74,168	)		—			—			—			—			—
Revisions of previous estimates		(157,680	)		6,721			(38,308	)		(189,267	)		(13,552	)		(20,523	)		(34,075	)		(223,342	)
Production		(31,300	)		1,107			(6,193	)		(36,386	)		(6,097	)		(3,919	)		(10,016	)		(46,402	)

December 31, 2020		359,658			(12,230	)		—			347,428			34,238			35,933			70,171			417,599

Proved Developed Reserves as of:
December 31, 2019		297,808			(12,782	)		54,716			339,742			40,752			47,690			88,442			428,184
December 31, 2020		261,079			(9,143	)		—			251,936			27,558			32,341			59,899			311,835
Proved Undeveloped Reserves as of:
December 31, 2019		168,391			(6,983	)		63,953			225,361			11,979			12,613			24,592			249,953
December 31, 2020		98,579			(3,087	)		—			95,492			6,680			3,592			10,272			105,764

Standardized measure of discounted future net cash flows

The following tables present the estimated pro forma standardized measure of discounted future net cash flows (the “pro forma standardized measure”) at December 31, 2020. The pro forma standardized measure information set forth below gives effect to the Pro Forma Transactions as if they had been completed on January 1, 2020. Independence Transaction Adjustments reflect adjustments to the standardized measure of discounted future net cash flows for the Titan Acquisition and the Noncontrolling Interest Carve-out. Contango Transaction Adjustments reflect adjustments to the standardized measure of discounted future net cash flows for the Mid-Con Acquisition and Grizzly Acquisition. Transaction Adjustments reflect adjustments related to the tax restructuring of the Company resulting from the Transactions. Each of these adjustments are further discussed within Note 3 – Adjustments to the pro forma financial statements. The disclosures below were determined by referencing the “Standardized Measure of Discounted Future Net Cash Flows” reported in Contango’s Annual Report on Form 10-K for the year ended December 31, 2020 and Independence’s combined and consolidated financial statements for the year ended December 31, 2020 included within the Proxy Statement/Prospectus. An explanation of the underlying methodology applied, as required by SEC regulations, can be found within the respective annual financial statements. The calculations assume the continuation of existing economic, operating and contractual conditions at December 31, 2020.

Therefore, the following estimated pro forma standardized measure is not necessarily indicative of the results that might have occurred had the Pro Forma Transactions been completed on January 1, 2020 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected because of various factors, including those discussed in “Risk Factors” beginning on page 51 within the Proxy Statement/Prospectus.

The pro forma standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves as of December 31, 2020 is as follows:


	(in thousands)
	Independence (Historical)			Independence Transaction Adjustments					Independence As Adjusted			Contango (Historical)			Contango Transaction Adjustments			Contango As Adjusted			Transaction Adjustments			Pro Forma Combined
				Noncontrolling Interest Carve-out			Titan Acquisition
Future cash inflows	$	8,232,932		$	(299,284	)	$	—	$	7,933,648		$	721,395		$	1,090,504		$	1,811,899		$	—		$	9,745,547
Future production costs		(4,280,563	)		151,983			—		(4,128,580	)		(411,069	)		(648,585	)		(1,059,654	)		—			(5,188,234	)
Future development costs(1)		(1,353,957	)		47,779			—		(1,306,178	)		(101,723	)		(91,286	)		(193,009	)		—			(1,499,187	)
Future income taxes		(30,155	)		1,102			—		(29,053	)		(18,901	)		(44,156	)		(63,057	)		(261,323	)		(353,433	)

Future net cash flows		2,568,257			(98,420	)		—		2,469,837			189,702			306,477			496,179			(261,323	)		2,704,693
Annual discount of 10% for estimated timing of cash flows		(1,240,397	)		49,170			—		(1,191,227	)		(74,115	)		(148,385	)		(222,500	)		101,776			(1,311,951	)

Standardized measure of discounted future net cash flows	$	1,327,860		$	(49,250	)	$	—	$	1,278,610		$	115,587		$	158,092		$	273,679		$	(159,547	)	$	1,392,742

(1)	Future development costs include future abandonment and salvage costs.

Changes in standardized measure

The changes in the pro forma standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the year ended December 31, 2020 are as follows:


	(in thousands)
	Independence (Historical)			Independence Transaction Adjustments						Independence As Adjusted			Contango (Historical)			Contango Transaction Adjustments			Contango As Adjusted			Transaction Adjustments			Pro Forma Combined
				Noncontrolling Interest Carve-out			Titan Acquisition
Beginning of year	$	3,110,848		$	(128,398	)	$	617,932		$	3,600,382		$	257,842		$	442,434		$	700,276		$	(457,640	)	$	3,843,018
Net change in prices and production costs		(1,184,939	)		47,708			(215,008	)		(1,352,239	)		(78,046	)		(244,343	)		(322,389	)		—			(1,674,628	)
Net change in future development costs		160,465			(6,545	)		209			154,129			9,360			80,460			89,820			—			243,949


	(in thousands)
	Independence (Historical)			Independence Transaction Adjustments						Independence As Adjusted			Contango (Historical)			Contango Transaction Adjustments			Contango As Adjusted			Transaction Adjustments			Pro Forma Combined
				Noncontrolling Interest Carve-out			Titan Acquisition
Sales and transfers of oil and natural gas produced, net of production expenses		(290,053	)		10,078			(104,284	)		(384,259	)		(68,787	)		(22,992	)		(91,779	)		—			(476,038	)
Extensions, discoveries, additions and improved recovery, net of related costs		31,688			(1,273	)		—			30,415			4,729			1,588			6,317			—			36,732
Purchase of reserves in place		176,480			—			(176,480	)		—			—			—			—			—			—
Revisions of previous quantity estimates		(887,395	)		37,936			(176,026	)		(1,025,485	)		(48,609	)		(115,676	)		(164,285	)		—			(1,189,770	)
Previously estimated development costs incurred		32,873			(1,160	)		5,202			36,915			—			3,773			3,773			—			40,688
Net changes in taxes		19,350			(850	)		3,132			21,632			17,922			(23,134	)		(5,212	)		343,857			360,277
Sale of reserves		—			—			—			(3,259	)		—			(3,259	)		—			(3,259	)
Accretion of discount		283,954			(11,695	)		62,106			334,365			28,655			44,243			72,898			(45,764	)		361,499
Change in the timing and other		(125,411	)		4,949			(16,783	)		(137,245	)		(4,220	)		(8,261	)		(12,481	)		—			(149,726	)

End of year	$	1,327,860		$	(49,250	)	$	—		$	1,278,610		$	115,587		$	158,092		$	273,679		$	(159,547	)	$	1,392,742


Delaware	001-41132	87-1133610
(State or Other Jurisdiction of Incorporation)	(Commission File Number)	(I.R.S. Employer Identification Number)


Exhibit		Description

23.1		Consent of Deloitte & Touche LLP, relating to the financial statements of Independence Energy LLC.

23.2		Consent of Grant Thornton LLP, relating to the financial statements of Contango Oil & Gas Company.

23.3		Consent of Ernst & Young LLP, relating to the financial statements of Liberty Energy LLC.

23.4		Consent of Netherland, Sewell & Associates, Inc.

23.5		Consent of Netherland, Sewell & Associates, Inc.

23.6		Consent of Netherland, Sewell & Associates, Inc.

23.7		Consent of Haas Petroleum Engineering Services, Inc.

23.8		Consent of Cawley, Gillespie & Associates, Inc.

23.9		Consent of W.D. Von Gonten and Company.

23.10		Consent of William M. Cobb & Associates, Inc.

99.1		Historical audited financial statements of Independence Energy LLC as of December 31, 2020 and 2019 and for the years ended December 31, 2020, 2019 and 2018.

99.2		Historical unaudited consolidated financial statements of Independence Energy LLC as of September 30, 2021 and for the nine months ended September 30, 2021 and 2020.


Exhibit		Description

99.3		Historical audited financial statements of Contango Oil & Gas Company as of December 31, 2020 and 2019 and for the years ended December 31, 2020 and 2019.

99.4		Historical unaudited financial statements of Contango Oil & Gas Company as of September 30, 2021 and December 31, 2020 and for the nine months ended September 30, 2021 and 2020.

99.5		Historical audited financial statements of Liberty Energy, LLC as of and for the year ended December 31, 2019.

99.6		Historical unaudited financial statements of Liberty Energy, LLC as of and for the six months ended June 30, 2020.

99.7		Unaudited pro forma condensed combined financial information as of September 30, 2021 and for the nine months ended September 30, 2021 and the year ended December 31, 2020.

99.8		Report of Netherland, Sewell & Associates, Inc. – Independence Upstream Holdings (incorporated by reference to Exhibit 99.4 to Crescent’s Registration Statement on Form S-4).

99.9		Report of Netherland, Sewell & Associates, Inc. – Independence Minerals (incorporated by reference to Exhibit 99.5 to Crescent’s Registration Statement on Form S-4).

99.10		Report of Haas Petroleum Engineering Services, Inc. – FDL Newark (incorporated by reference to Exhibit 99.6 to Crescent’s Registration Statement on Form S-4).

99.11		Report of Haas Petroleum Engineering Services, Inc. – FDL Renee (incorporated by reference to Exhibit 99.7 to Crescent’s Registration Statement on Form S-4).

99.12		Report of Haas Petroleum Engineering Services, Inc. – FDL Gardendale (incorporated by reference to Exhibit 99.8 to Crescent’s Registration Statement on Form S-4).

99.13		Report of Cawley, Gillespie & Associates, Inc. – Venado Palo Verde (incorporated by reference to Exhibit 99.9 to Crescent’s Registration Statement on Form S-4).

99.14		Report of Cawley, Gillespie & Associates, Inc. – Venado Comanche (incorporated by reference to Exhibit 99.10 to Crescent’s Registration Statement on Form S-4).

99.15		Report of Netherland, Sewell & Associates, Inc. – Bridge Energy (incorporated by reference to Exhibit 99.11 to Crescent’s Registration Statement on Form S-4).

99.16		Report of William M. Cobb & Associates, Inc. (incorporated by reference to Exhibit 99.1 to Contango’s Annual Report on Form 10-K for the year ended December 31, 2020).

99.17		Report of W.D. Von Gonten and Company (incorporated by reference to Exhibit 99.2 to Contango’s Annual Report on Form 10-K for the year ended December 31, 2020).

99.18		Report of Netherland, Sewell & Associates, Inc. – Liberty Energy, LLC (incorporated by reference to Exhibit 99.14 to Crescent’s Registration Statement on Form S-4).

104		Cover Page Interactive Data File (embedded within the Inline XBRL document).


CRESCENT ENERGY COMPANY

By:		/s/ Brandi Kendall
Name:		Brandi Kendall
Title:		Chief Financial Officer


NETHERLAND, SEWELL & ASSOCIATES, INC.

By:		/s/ Danny D. Simmons
		Danny D. Simmons, P.E.
		President and Chief Operating Officer


		750 N. St. Paul Street
		Suite 1750
		Dallas, Texas 75201
		Phone (214) 754-7090


HAAS PETROLEUM ENGINEERING SERVICES, INC.
By:		/s/ J. Thaddeus Toups
		J. Thaddeus Toups, PE
		President


12770 Coit Road, Suite 907		Tel: (972) 385-0354
Dallas, Texas 75251		Fax: (972) 788-5165
		E-Mail: office@wmcobb.com


Revenues:
Oil, gas and other sales	$	103,699,124
Other income		32,964

Total revenues, net		103,732,088
Operating expenses:
Production		64,754,033
Exploration		676,410
Depreciation, depletion, amortization and accretion		107,131,208
Impairment of assets		231,206,101
General and administrative		530,953

Total operating expenses		404,298,705
Loss on sale of assets		(651,655	)
Gain on settlement of asset retirement obligations		359,576

Total operating income		(300,858,696	)
Other expense:
Investment management fees and expenses		(2,519,605	)

Other expense		(2,519,605	)

Loss before income taxes		(303,378,301	)
Income tax expense		(22,366	)

Total comprehensive loss	$	(303,400,667	)


Expected income tax expense (benefit)	$	(63,709,443	)
Disregarded entity income		63,709,443

Federal income tax expense (benefit)		—
State tax expense		22,366

Income tax expense	$	22,366