Empire Petroleum Corp 10-K for FY2022
Empire Petroleum Corp (EP)
About this 10-K
Empire Petroleum Corp filed this 10-K on March 31, 2023, covering the fiscal year ended December 31, 2022 (FY2022).
Headline figures
Fiscal year ended December 31, 2022, as reported in this filing, compared with the same period a year earlier where the filing states it.
- Revenue
- $52.89M
- up 95.2% from $27.09M a year earlier
- Net income
- $7.08M
- compared with a net loss of $18.61M a year earlier
- Diluted EPS
- $0.30
- compared with -$1.27 a year earlier
UNITED
STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
OF THE SECURITIES EXCHANGE ACT OF 1934
For
the fiscal year ended
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____________ to _____________
Commission
File Number
(Exact name of registrant as specified in its charter)
_________________
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(Address of Principal Executive Offices) (Zip
Code)
Registrant's
telephone number, including area code: (
Securities registered pursuant to Section 12(b) of the Act:
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Securities registered pursuant to 12(g) of the Act: None
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by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☐ Yes
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by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes
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by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
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by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule
405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant
was required to submit such files). ☑
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer ☐ | Accelerated filer ☐ | Smaller reporting company |
Emerging growth company |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐
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by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☑
The
aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the closing sales
price of such common equity as of the last business day of the registrant's most recently completed second fiscal quarter, was $
The number of shares of the registrant's common stock, $0.001 par value, outstanding as of March 21, 2023 was .
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive Proxy Statement relating to the registrant’s 2023 annual meeting of stockholders have been incorporated by reference into Part III of this Annual Report on Form 10-K.
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EMPIRE PETROLEUM CORPORATION
FORM 10-K
TABLE OF CONTENTS
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FORWARD-LOOKING STATEMENTS
Certain
statements in this Annual Report on Form 10-K constitute “forward-looking statements” within the meaning of Section 27A of
the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as
amended (the “Exchange Act”). Additionally, forward-looking statements may be made orally or in press releases, conferences,
reports, on our website or otherwise, in the future by us or on our behalf. Such statements are generally identifiable by the terminology
used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,”
“forecasted,” “intend,” “may,” “might,” “plan,” “potential,”
“predict,” “project,” “should,” “would” or other similar words, although not all forward-looking
statements contain such identifying words.
By their very nature, forward-looking statements require management to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Factors that could cause actual results to differ materially from the results discussed in such forward-looking statements include, but are not limited to, those discussed in Item 1A ("Risk Factors") and elsewhere in this Form 10-K and in other documents that we file with or furnish to the Securities and Exchange Commission (the "SEC"), and the following:
| • | changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids; |
| • | our ability to replace reserves and efficiently develop current reserves; |
| • | management's ability to execute our business plan; |
| • | delays and other difficulties related to producing oil, natural gas and natural gas liquids; |
| • | delays and other difficulties related to regulatory and governmental approvals and restrictions; |
| • | availability of sufficient capital to execute management's business plan, including from future cash flows, available borrowing capacity under revolving credit facilities and otherwise; |
| • | management's ability to make acquisitions on economically acceptable terms and management's ability to integrate acquisitions; |
| • | weather and environmental conditions; |
| • | unforeseen engineering, mechanical or technological difficulties in working over wells; |
| • | costs of operations and operating hazards; |
| • | competition from other natural resource companies; |
| • | unanticipated reductions in the borrowing base under the revolving credit facility we are party to; |
| • | the availability of sufficient pipeline and other transportation facilities and equipment to carry our production to market and the impact of these facilities on our realized prices; |
| • | our ability to retain key members of senior management and key technical and financial employees; |
| • | the identification of and severity of adverse events and governmental responses to these or other environmental events; |
| • | future ESG compliance developments and increased attention to such matters which could adversely affect our ability to raise equity and debt capital; |
| • | the effect of our derivative activities; |
| • | impacts of public health crises, pandemics and epidemics, such as the coronavirus pandemic ("COVID-19"); |
| • | the effects of governmental and environmental regulation; and |
| • | general economic conditions. |
All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this Form 10-K. Other than as required by applicable securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations, or otherwise. Readers should not place undue reliance on these forward-looking statements. All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made.
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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry and within this report.
Bbl – One barrel or 42 U.S. gallons liquid volume of oil or other liquid hydrocarbons.
Bcf – One billion cubic feet of natural gas.
Boe – Barrel of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent. The ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas differs significantly from the price for a barrel of oil. A barrel of NGLs also differs significantly in price from a barrel of oil.
CG&A – Cawley, Gillespie & Associates, Inc.
DD&A – Depreciation, depletion and amortization.
ESG – Environmental, Social and Governance.
Field – An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
LOE – Lease Operating Expense, a current period expense incurred to operate a well.
MBbls – One thousand barrels of crude oil or other liquid hydrocarbons.
MBoe – One thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.
MMBoe – One million barrels of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.
Mcf – One thousand cubic feet.
MMcf – One million cubic feet.
Net acres or net wells – The sum of the fractional working interests owned in gross acres or gross wells.
NYSE American – NYSE American Stock Exchange.
NGLs – Natural gas liquids measured in barrels. NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics.
Net revenue interest or NRI –The total revenue interest controlled by an entity in a specific oil or gas production unit, including a well, lease, or drilling unit.
Operator – An oil and gas joint venture participant that manages the joint venture, pays venture costs, and bills the venture’s non-operators for their share of venture costs. The operator is also responsible to market all oil, gas, and NGL production, except for those non-operators who take their production in-kind.
OTCQB – The over-the-counter (OTC) market exchange for the middle tier of three marketplaces for trading OTC stocks.
Overriding Royalty Interest or ORRI – A royalty interest that is created out of the operating or working interest. Unlike a royalty interest, an overriding royalty interest terminates with the operating interest from which it was created or carved out of.
Plugging and abandonment or P&A – Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another stratum or to the surface.
Proved developed producing reserves or PDP – Reserves that can be expected to be recovered from existing wells and completions with existing equipment and operating methods.
PV-10 – The present value, discounted at 10% per annum, of future net revenues (estimated future gross revenues less estimated future costs of production, development, and asset retirement costs) associated with reserves and is not necessarily the same as market value. PV-10 does not include estimated future income taxes. Unless otherwise noted, PV-10 is calculated using the pricing scheme required by the SEC. PV-10 of proved reserves is calculated the same as the standardized measure of discounted future net cash flows, except that the standardized measure of discounted future net cash flows includes future estimated income taxes discounted at 10% per annum.
Royalty Interest or RI – The mineral owner’s share of production, free of costs, but subject to severance taxes unless the lessor is a government.
SEC – United States Securities and Exchange Commission.
Standardized Measure – The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue.
Undeveloped acreage – Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Working interest or WI – The ownership interest, generally defined in a JOA, that gives the owner the right to drill, produce and/or conduct operating activities on the property and share in the sale of production, subject to all royalties, overriding royalties and other burdens and obligates the owner of the interest to share in all costs of exploration, development operations and all risks in connection therewith.
Workover – Operations on a producing well to restore or increase production.
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PART I
ITEM 1. BUSINESS.
In this Form 10-K, references to “Empire”, the “Company”, “we”, “our”, and “us” refer to Empire Petroleum Corporation and its wholly-owned subsidiaries, unless context indicates otherwise.
We uplisted from the OTCQB to the NYSE American effective March 8, 2022. Immediately prior to the listing, a reverse stock split of 1 for 4 occurred. All pricing and share amounts for periods prior to the reverse stock split have been stated at post-reverse split amounts.
On March 8, 2022, our common stock began trading on the NYSE American under the symbol “EP” and CUSIP 292034303. Prior to trading on the NYSE American, our common stock was accessible on the OTCQB.
Overview
Empire Petroleum Corporation is an independent energy company that engages in unlocking value in developed assets. Empire operates the following wholly-owned subsidiaries in its areas of operations:
| • | Empire New Mexico LLC d/b/a Green Tree New Mexico (“Empire New Mexico”) | |
| • | Empire Rockies Region |
| ○ | Empire North Dakota LLC (“Empire North Dakota”) |
| ○ | Empire North Dakota Acquisition LLC (“Empire NDA”) |
| • | Empire Texas (“Empire Texas”), consisting of the following entities: |
| ○ | Empire Texas LLC |
| ○ | Empire Texas Operating LLC |
| ○ | Empire Texas GP LLC |
| ○ | Pardus Oil & Gas Operating, LP (owned 1% by Empire Texas GP LLC and 99% by Empire Texas LLC) |
| • | Empire Louisiana LLC (“Empire Louisiana”) |
Empire was incorporated in the state of Delaware in 1985. The consolidated financial statements of Empire Petroleum Corporation and subsidiaries include the accounts of the Company and its wholly-owned subsidiaries.
Our mission is to increase shareholder value by building oil and natural gas reserves in strategic plays in the United States. To accomplish its mission, we plan on executing the following business strategies:
| • | Cost-effectively optimize well production | |
| • | Reduce unit operating costs and improve margins |
| • | Target proved developed producing acquisitions in predictable fields that have historically had low production decline and long lives |
| • | Focus on high-quality assets that add scale and provide synergies to our existing portfolio and core areas of operation |
We operate as a single segment as each of our operating areas have similar economic characteristics and each meet the criteria for aggregation as defied by accounting standards related to disclosures about segments of an enterprise.
Properties
We are an independent operator in four geographic areas in the United States. As operator, we manage and influence production on operated properties. We use a combination of experienced field personnel and third-party service providers to execute our mission. Our properties have reasonably predictable production profiles and cash flows, subject to commodity price and cost fluctuations.
As is common in the industry in which we operate, we selectively participate in drilling and developmental activities in non-operated properties. Decisions to participate in non-operated properties are made after technical and economic analysis of the projects which also considers the operating expertise and historical track record of the operators.
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Empire New Mexico
Empire New Mexico was formed when we purchased producing assets from XTO in May 2021. These assets are located in Lea County, New Mexico and consist of a contiguous and consolidated acreage position consisting of 48,000 gross (40,000 net) acres held by production from approximately 730 wells with an average WI of 72% and average NRI of 61% and 14 RI wells with an average ORRI of 11%. Empire New Mexico’s assets primarily produce oil with natural gas and NGLs accompanying oil production. Empire New Mexico’s properties are in the following formations:
| • | Grayburg/San Andres (primary source of production) |
| • | Queen-Seven Rivers-Yates |
| • | Devonian |
| • | Abo |
| • | Blineberry |
| • | Tubb |
| • | Drinkard |
Empire North Dakota
Empire North Dakota operates approximately 230 producing properties with an average WI of 89% and NRI of 61% in North Dakota and western Montana that were acquired in April 2019. These properties primarily produce oil with some related gas production. Assets are located in the following formations:
| • | Madison (primary source of production) |
| • | Bakken |
| • | Duperow |
| • | Red River |
| • | Ratcliffe/Mission Canyon |
These assets have experienced near-flat production rates over the last five years. We have been able to capitalize on operational improvements to allow more immediate recovery of reserves.
Empire Texas
In April 2020, Empire Texas acquired approximately 140 gross wells and approximately 30,000 net acres with an average operated WI of 96% and an average operated NRI of 79% as well as 77 miles of gathering lines and pipelines with related facilities and equipment. Empire Texas owns concentrated acreage and stacked pay in the historically prolific East Texas Basin. Assets are concentrated in the Fort Trinidad Field in Houston and Madison Counties with high working interest and historical production from eight separate formations.
Empire Louisiana
Empire Louisiana acquired its assets in late 2018 and has 10 producing properties and three saltwater disposal wells in the following formations:
| • | Miocene |
| • | Frio |
| • | Cockfield |
| • | Wilcox |
Empire Louisiana’s assets primarily produce oil from properties with average WI of 58% and NRI of 47%.
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Production and Operating Data
The following table sets forth a summary of our production and operating data for the years ended December 31, 2022 and 2021. Because of normal production declines, increased or decreased production due to future acquisitions, divestitures, and development, fluctuations in commodity prices and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.
| Year Ended December 31, 2022 | Year Ended December 31, 2021 | |||||||
| Production and operating data: | ||||||||
| Net production volumes: | ||||||||
| Oil (Bbl) | 482,818 | 333,158 | ||||||
| Natural gas (Mcf) | 875,647 | 622,474 | ||||||
| Natural gas liquids (Bbl) | 160,809 | 102,893 | ||||||
| Total (Boe) | 789,568 | 539,796 | ||||||
| Average price per unit: | ||||||||
| Oil (a) | $ | 93.16 | $ | 67.01 | ||||
| Natural gas (a)(b) | $ | 5.18 | $ | 3.68 | ||||
| Natural gas liquids (b) | $ | 22.76 | $ | 28.08 | ||||
| Total (Boe) | $ | 67.34 | $ | 50.95 | ||||
| Operating costs and expenses per Boe: | ||||||||
| Lease operating expense | $ | 29.87 | $ | 24.61 | ||||
| Production and ad valorem taxes | $ | 4.99 | $ | 3.90 | ||||
| Depreciation, depletion, amortization and accretion | $ | 4.19 | $ | 6.89 | ||||
| General & administrative | $ | 15.62 | $ | 15.68 | ||||
| (a) | Excludes the effect of net cash receipts from (payments on) derivatives. |
| (b) | Includes gathering and processing costs in 2022 and 2021 that were previously reported in Lease operating expense within Operating Costs and expenses. |
At December 31, 2022 and 2021, we had approximately 1,100 wells which we operated.
We completed a pilot drilling program on four wells in North Dakota and are in the process of completing these wells as of December 31, 2022. During 2022, we had no other drilling activity with the exception of four non-operated wells. No wells were in progress as of December 31, 2021, and we had no drilling activity during 2021 with the exception of four non-operated wells.
We have no delivery commitments for oil or natural gas.
Oil and Natural Gas Reserves
Our primary mission is to optimize existing producing properties; as such, there are no reserves estimated for undeveloped properties, though we own acreage that can be drilled in the future and are also a non-operator WI owner on acreage subject to future drilling activities. The following table represents our oil and natural gas reserves at December 31, 2022 and 2021.
| Oil | Natural Gas | NGL | ||
| (Mbbl) | (MMcf) | (Mbbl) | MBoe | |
| Proved developed at December 31, 2022 | 8,826 | 12,936 | 2,262 | 13,244 |
| Proved developed at December 31, 2021 | 8,448 | 11,205 | 87 | 10,403 |
Net proved reserves were calculated using an unweighted arithmetic average of the first-day-of-the-month price within the 12-month period for the year. All prices and costs associated with operating wells were held constant in accordance with SEC guidelines. Prices of $91.14 per barrel of oil, $4.23 per Mcf and $36.29 per barrel of NGL were utilized at December 31, 2022. Prices of $64.31 per barrel and $7.34 per Mcf were utilized at December 31, 2021. Natural gas pricing in 2022 includes prices received for NGLs during the year. In 2021, we did not separately report the NGLs in New Mexico.
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Reserve Estimation Process
Reserve estimation is a subjective process as the underground accumulations of crude oil and natural gas cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, and future oil and natural gas prices may differ from those assumed in these estimates. Our internal professionals work closely with our external engineers to ensure the integrity, accuracy, and timeliness of data that is furnished to them for their reserve estimation process.
We engage an independent petroleum engineering firm, CG&A, to prepare our annual reserve estimates and rely on CG&A’s expertise to ensure that reserve estimates are prepared in accordance with SEC guidelines.
The technical person primarily responsible for the preparation of the reserve report is Zane Meekins, Executive Vice President. Mr. Meekins has been with CG&A since 1989 and graduated from Texas A&M University in 1987 with a bachelor's degree in Petroleum Engineering. He is a registered professional engineer in Texas and has more than 30 years of experience in the estimation and evaluation of oil and natural gas reserves. He is also a member of the Society of Petroleum Engineers and The Society of Petroleum Evaluation Engineers.
Brian Weatherl, Vice President of Engineering, is responsible for our reservoir engineering, and is a qualified reserve estimator and is responsible for overseeing CG&A during the preparation of the annual reserve estimates. His professional qualifications meet or exceed the qualifications of reserve estimators set forth in the “Standards Pertaining to Estimation and Auditing of Oil and Natural Gas Reserve Information” promulgated by the Society of Petroleum Engineers. His qualifications include a Bachelor of Science degree in Petroleum Engineering from the University of Tulsa in 1984 and he is a member of the Society of Petroleum Engineers. Mr. Weatherl has been estimating and evaluating reserves for over 35 years.
The primary inputs to the reserve estimation process are technical information, financial data, ownership interest and production data. The relevant field and reservoir technical information, which is updated at least annually, is assessed for validity when CG&A has technical meetings with our personnel. Current revenue and expense information is obtained from accounting records, which are subject to external quarterly reviews, annual audits, and internal controls over financial reporting. All current financial data such as commodity prices, lease operating expenses, production taxes and field level commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Our ownership in mineral interests and well production data are subject to internal controls and are incorporated into the reserve database as well as verified internally by our personnel to ensure accuracy and completeness. Once the reserve database has been updated with current information, and the relevant technical support material has been assembled, CG&A meets with technical personnel to review field performance and future development plans in order to verify the validity of estimates. Following these reviews, the reserve database is furnished to CG&A so that it can prepare its independent reserve estimate and final report. The reserve estimates prepared by CG&A are reviewed and compared to internal estimates by Mr. Weatherl. Material reserve estimation differences are reviewed between CG&A and our technical personnel and additional data is provided to address any variances. If the supporting documentation does not justify additional changes, CG&A reserves are accepted. In the event that additional data supports a reserve estimation adjustment, CG&A will analyze the additional data and may make changes it solely deems necessary. Additional data is usually comprised of updated production information on new wells. Once the review is completed and all material differences are reconciled the reserve report is finalized and our reserve database is updated with the final estimates provided by CG&A.
COVID-19
Despite recoveries in commodity prices, COVID-19 has impacted and may continue to impact the global economy and disrupt global supply chains and has the potential to continue to create significant volatility and disruption of financial and commodity markets. The extent of the continuing impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute business strategies and initiatives in the expected timeframes, is uncertain and depends on various factors outside of our control, including how the pandemic continues to evolve and how measures taken in response to its effects impact the demand for oil and natural gas, the availability of personnel, equipment, and services critical to our ability to operate our properties and the impact of potential governmental restrictions. There is uncertainty regarding the extent and duration of any disruption.
Marketing Arrangements
We market our oil and natural gas in accordance with standard energy industry practices. This marketing effort endeavors to obtain the combined highest netback and most secure market available at that time.
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We sell oil production at the lease locations to third-party purchasers via truck transport or pipeline. We do not transport, refine or process the oil we produce. We sell our produced oil under contracts using market-based pricing, which is adjusted for differentials based upon oil quality.
We sell our natural gas and natural gas liquids under purchase contracts using market-based pricing, which is primarily sold at the lease location.
Principal Customers
We sell our oil, natural gas, and NGL production to marketers which is transported by truck or pipeline to storage facilities arranged by the marketers. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted.
For 2022, 68% of revenues from oil, natural gas, and NGL sales were to four customers. For 2021, 63% of revenues from oil, natural gas, and NGL sales were to four customers. While the loss of these purchasers may result in a temporary interruption in sales of, or a lower price for, our production, we believe that the loss of these purchasers would not have a material adverse effect on our operations, as there are alternative purchasers in our producing regions.
Competition
The oil and natural gas industry in the areas in which we operate is highly competitive. We encounter strong competition from numerous parties, ranging generally from small independent producers to major integrated companies. We primarily encounter significant competition in acquiring properties. At higher commodity prices, we also face competition in contracting for oil field services, rigs, pressure pumping and workover equipment and securing trained personnel. Many of these competitors have financial, technical and personnel resources substantially larger than ours. As a result, our competitors may be able to pay more for desirable properties, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.
In addition to competition for drilling, pressure pumping and workover equipment, we are also affected by the availability of related equipment and materials. The oil and natural gas industry periodically experiences shortages of drilling and workover rigs, equipment, pipe, materials and personnel, which can delay workover and exploration activities and cause significant price increases. We are unable to predict the timing or duration of any such shortages.
Seasonality of Business
Weather conditions often affect the demand for, and prices of, natural gas and can also delay oil and natural gas production. Demand for natural gas is traditionally higher in the winter, resulting in higher natural gas prices during the first and fourth quarters. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results realized on an annual basis.
Markets; Price Volatility
The market price of oil and natural gas is volatile, subject to speculative movement and depends upon numerous factors beyond our control, including expectations regarding inflation, global and regional demand, political and economic conditions and production costs. Future profitability, if any, will depend substantially upon the prevailing prices for oil and natural gas. If the market price for oil and natural gas remains depressed in the future, it could have a material adverse effect on our ability to raise additional capital necessary to finance operations. Lower oil and natural gas prices may also reduce the amount of oil and natural gas, if any, that can be produced economically from our properties. We anticipate that the prices of oil and natural gas will fluctuate in the near future.
Regulation
The oil and natural gas industry is subject to extensive federal, state and local laws and regulations governing the production, transportation and sale of hydrocarbons as well as the taxation of income resulting therefrom.
Legislation affecting the oil and natural gas industry is constantly changing. Numerous federal and state departments and agencies have issued rules and regulations applicable to the oil and natural gas industry. In general, these rules and regulations regulate, among other things, the extent to which acreage may be acquired or relinquished; spacing of wells; measures required for preventing waste of oil and natural gas resources; and, in some cases, rates of production. The heavy and increasing regulatory burdens on the oil and natural gas industry increase our cost of doing business and, consequently, affect profitability.
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Our oil and natural gas operations are also subject to numerous federal, state and local laws and regulations relating to environmental protection. These laws govern, among other things, the amounts and types of substances and materials that may be released into the environment, the issuance of permits in connection with exploration, drilling and production activities, the reclamation and abandonment of wells and facility sites and the remediation of contaminated sites. These laws and regulations may impose substantial liabilities if we fail to comply or if any contamination results from our operations.
Employees
At December 31, 2022, we had forty full-time employees, not including contract personnel and outsourced service providers. Our team is broadly experienced in oil and natural gas operations and follows a strategy of outsourcing most accounting, human resources, and other non-core functions.
Office Locations
Our corporate headquarters are at 2200 South Utica Place, Suite 150, Tulsa, Oklahoma, with field offices in North Dakota, Texas, and New Mexico.
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ITEM 1A. RISK FACTORS.
Our operations are subject to various risks and uncertainties in the ordinary course of business. The following summarizes significant risks and uncertainties that may adversely affect our operations or financial position. Risks and uncertainties discussed below are not a comprehensive listing of those faced by us. Additional risks not presently known or that are deemed immaterial may also affect us. Readers should carefully consider the risk factors included below and other information included and incorporated by reference into this Annual Report on Form 10-K.
Reserves
The Standardized Measure and PV-10 of estimated reserves may not be accurate estimates of the current fair value of estimated proved oil and natural gas reserves.
Standardized Measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. PV-10, a non-GAAP (Generally Accepted Accounting Principles) financial measure, is a similar reporting convention that we have disclosed in this report. Both measures require the use of operating and development costs prevailing as of the date of computation. Consequently, they will not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may they reflect the actual costs that will be required to produce or develop the oil and natural gas properties. Accordingly, estimates included in this report of future net cash flows may be materially different from the future net cash flows that are ultimately received. In addition, the 10 percent discount factor, which is required by the rules and regulations of the SEC to be used in calculating discounted future net cash flows for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
Therefore, Standardized Measure and PV-10 included in this report should not be construed as accurate estimates of the current market value of our proved reserves.
Estimates of proved reserves and future net cash flows are not precise. The actual quantities of our proved reserves and future net cash flows may prove to be lower than estimated.
Numerous uncertainties exist in estimating quantities of proved reserves and future net cash flows therefrom. Estimates of proved reserves and related future net cash flows are based on various assumptions, which may ultimately prove to be inaccurate. Petroleum engineering is a subjective process of estimating accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including the following:
| • | historical production from the area compared with production from other producing areas; |
| • | the assumed effects of regulations by governmental agencies; |
| • | the quality, quantity and interpretation of available relevant data; |
| • | assumptions concerning future commodity prices; and |
| • | assumptions concerning future operating costs, severance and ad valorem taxes, development costs and workover and remedial costs. |
Because all reserve estimates are to some degree subjective, each of the following items, or other items not identified below, may differ materially from those assumed in estimating reserves:
| • | the quantities of oil and natural gas that are ultimately recovered; |
| • | the production and operating costs incurred; |
| • | the amount and timing of future development expenditures; and |
| • | future commodity prices. |
Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data. Our actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material.
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As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on the average previous twelve months first-of-month prices preceding the date of the estimate and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:
| • | the amount and timing of actual production; |
| • | levels of future capital spending; |
| • | increases or decreases in the supply of or demand for oil and natural gas; and |
| • | changes in governmental regulations or taxation. |
Accordingly, estimates included in this report of future net cash flows may be materially different from the future net cash flows that are ultimately received. Therefore, the estimates of discounted future net cash flows in this report should not be construed as accurate estimates of the current market value of our proved reserves.
Unless reserves are replaced, production and estimated reserves will decline, which may adversely affect our financial condition, results of operations and/or cash flows.
Producing oil and natural gas reservoirs are generally characterized by declining production rates that may vary depending upon reservoir characteristics and other factors. Estimates of the decline rate of an oil or natural gas well are inherently imprecise and may be less precise with respect to new or emerging oil and natural gas formations with limited production histories than for more developed formations with established production histories. Estimated future oil and natural gas reserves and production and, therefore, cash flows and results of operations are highly dependent upon our success in efficiently developing and exploiting current properties and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, cash flows and the value of reserves may decrease, adversely affecting our business, financial condition and results of operations.
Financing
We have indebtedness and may incur substantially more debt. Higher levels of indebtedness make us more vulnerable to economic downturns and adverse business developments.
Our total indebtedness at December 31, 2022 was $7.2 million. Our subsidiaries Empire Louisiana and Empire North Dakota had approximately $5.9 million of outstanding aggregate principal indebtedness at December 31, 2022. At December 31, 2022, commitments from the financial institution under our Senior Revolving Credit Facility (as amended, the “Credit Facility”) were approximately $6.1 million, of which approximately $300,000 was unused commitments. Management continues to review existing indebtedness, and may seek to repay, refinance, repurchase, redeem, exchange or otherwise terminate existing indebtedness. If we do seek to refinance existing indebtedness, there can be no guarantee that we would be able to execute the refinancing on favorable terms or at all.
As a result of indebtedness, we use a portion of our cash flow to pay interest, which reduces the amount available to fund operations and other business activities and could limit flexibility in planning for or reacting to changes in the business and the industry in which we operate. Indebtedness under the Credit Facility is at a variable interest rate, and so a rise in interest rates will generate greater interest expense.
We may incur substantially more debt in the future. The Credit Facility contains restrictions on the incurrence of additional indebtedness.
Increases in the level of indebtedness could have adverse effects on our financial condition and results of operations, including:
| • | imposing additional cash requirements on us in order to support interest payments, which reduces the amount we have available to fund our operations and other business activities; |
| • | increasing the risk that we may default on our debt obligations; |
| • | increasing our vulnerability to adverse changes in general economic and industry conditions, economic downturns and adverse developments in our business; |
| • | limiting our ability to sell assets, engage in strategic transactions or obtain additional financing for working capital, capital expenditures, general corporate and other purposes; |
| • | limiting our flexibility in planning for or reacting to changes in our business and the industry in which we operate; and |
| • | increasing our exposure to a rise in interest rates, which will generate greater interest expense. |
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Our ability to meet our debt obligations and reduce our level of indebtedness depends on future performance, which is affected by general economic conditions and financial, business and other factors, many of which are outside of the scope of management’s control.
Our business requires substantial capital expenditures. Management may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a decline in oil and natural gas reserves.
The oil and natural gas industry is capital intensive. Management makes and expects to continue to make substantial capital expenditures for the acquisition and development of reserves. We intend to finance future capital expenditures through cash flow from operations or incurring additional indebtedness. However, cash flow from operations and access to capital are subject to a number of variables, including:
| • | the volume of oil, natural gas, and NGLs we are able to produce from existing wells; |
| • | ability to transport oil and natural gas to market; |
| • | the prices at which commodities are sold; |
| • | the costs of producing oil and natural gas; |
| • | global and domestic demand for oil and natural gas; |
| • | global credit and securities markets; |
| • | the ability and willingness of lenders and investors to provide capital and the cost of the capital; |
| • | ability to acquire, locate and produce new reserves; |
| • | the impact of potential changes in our credit ratings; and |
| • | proved reserves. |
We may not generate expected cash flows and obtain the capital necessary to sustain our operations at current or anticipated levels. A decline in cash flow from operations or our financing needs may require management to revise our capital program or alter or increase capitalization substantially through the issuance of debt or equity securities. The issuance of additional equity securities could have a dilutive effect on the value of our common stock. Additional borrowings under the Credit Facility or the issuance of additional debt securities will require that a greater portion of cash flow from operations be used for the payment of interest and principal on debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions. Additional financing also may not be available on acceptable terms or at all. In the event additional capital resources are unavailable, management may curtail activities or be forced to sell some assets on an untimely or unfavorable basis.
If we are unable to comply with the covenants in our agreements governing our indebtedness, including the Credit Facility, there could be a default under the terms of such agreements, which could result in an acceleration of payment of funds that we have borrowed.
Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many of which management is unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance debt, sell assets or sell additional equity on terms that we may not find attractive if it may be done at all. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest, if any, on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the agreements governing our indebtedness, including the Credit Facility, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default:
| • | the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest; |
| • | the lenders could elect to terminate their commitments thereunder and cease making further loans; and |
| • | we could be forced into bankruptcy or liquidation. |
If our operating performance declines, we may need to obtain waivers under the Credit Facility to avoid being in default. If we breach our covenants and cannot obtain a waiver from the required lender, we would be in default and the lender could exercise its rights, as described above, and we could be forced into bankruptcy or liquidation.
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A negative shift in stakeholder sentiment towards the oil and natural gas industry and increased attention to ESG matters and conservation matters could adversely affect our ability to raise equity and debt capital.
Much of the investor community has developed negative sentiment towards investing in our industry over the past few years. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. Some investors, including certain public and private fund management firms, pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on environmental, social and governance considerations. Certain other stakeholders have pressured private equity firms and commercial and investment banks to stop funding oil and gas projects. Such developments have resulted and could continue to result in downward pressure on the stock prices of oil and natural gas companies, including ours. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results.
Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us or our operators. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.
Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Currently, there are no universal standards for such scores or ratings, but the importance of sustainability evaluations is becoming more broadly accepted by investors and stockholders. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our access to and costs of capital. Also, institutional lenders may decide not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects.
General Operations
The oil and natural gas industry is highly competitive, and our size may put us at a disadvantage in competing for resources.
The oil and natural gas industry is highly competitive where our properties and operations are concentrated. We compete with major integrated and larger independent oil and natural gas companies in seeking to acquire desirable oil and natural gas properties and leases and for the equipment and services required to develop and operate properties. Many of our competitors have financial and other resources that are substantially greater than ours, which makes acquisitions of acreage or producing properties at economic prices difficult. Significant competition also exists in attracting and retaining technical personnel, including geologists, geophysicists, engineers, landmen and other specialists, as well as financial and administrative personnel. Hence, we may be at a competitive disadvantage to companies with larger financial resources than ours.
A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
| • | changes in global supply and demand for oil and natural gas, which could be negatively affected by concerns about public health crises, pandemics and epidemics, such as the COVID-19 pandemic; |
| • | the price and quantity of imports of foreign oil and natural gas; |
| • | political conditions, including trade or other economic sanctions, armed conflict in Ukraine, the price cap on Russian oil and embargoes, in or affecting other oil-producing activity; |
| • | the level of global oil and natural gas exploration and production activity; |
| • | the level of global oil and natural gas inventories; |
| • | weather conditions; |
| • | technological advances affecting energy consumption; and |
| • | the price and availability of alternative fuels. |
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Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. Lower prices also negatively impact the value of our proved reserves. Volatility in the price of oil could force us (as well as other operators) to re-evaluate our current capital expenditure budget and make changes accordingly that we believe are in the best interest of us and our stockholders. A substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
Our producing properties and proved reserves are concentrated in New Mexico, North Dakota, Montana, Texas, and Louisiana, making us vulnerable to risks associated with operating in limited major geographic areas.
Our producing properties are geographically concentrated in New Mexico, North Dakota, Montana, Texas, and Louisiana. At December 31, 2022, all of our total estimated proved reserves were attributable to properties located in these areas. As a result of this concentration, we are exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by governmental regulation, processing or transportation capacity constraints, market limitations, severe weather events, water shortages or other drought related conditions or interruption of the processing or transportation of oil or natural gas.
This concentration of assets exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.
Our insurance policies may not adequately protect us against certain unforeseen risks.
In accordance with customary industry practice, we maintain insurance against some, but not all, of the risks described in this report. There can be no assurance that any insurance will be adequate to cover our losses or liabilities. We cannot predict the continued availability of insurance, or its availability at premium levels that justify its purchase.
We are subject to various environmental risks, and governmental regulation relating to environmental matters.
We are subject to a variety of federal, state and local governmental laws and regulations related to the storage, use, discharge and disposal of toxic, volatile or otherwise hazardous materials. These regulations subject us to increased operating costs and potential liability associated with the use and disposal of hazardous materials. Although these laws and regulations have not had a material adverse effect on our financial condition or results of operations, there can be no assurance that we will not be required to make material expenditures in the future. Moreover, we anticipate that such laws and regulations will become increasingly stringent in the future, which could lead to material costs for environmental compliance and remediation by us. Any failure by us to obtain required permits for, control the use of, or adequately restrict the discharge of hazardous substances under present or future regulations could subject us to substantial liability or could cause our operations to be suspended. Such liability or suspension of operations could have a material adverse effect on our business, financial condition and results of operations.
Our activities are subject to extensive governmental regulation. Oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic or political conditions. From time to time, regulatory agencies have imposed price controls and limitations on production in order to conserve supplies of oil and natural gas. In addition, the production, handling, storage, transportation and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. To date, expenditures related to complying with these laws and for remediation of existing environmental contamination have not been significant in relation to our operations. There can be no assurance that the trend of more expansive and stricter environmental legislation and regulations will not continue.
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As a result of previous low prices for oil, natural gas and NGL, we may be required to take significant future write-downs of the financial carrying values of our properties in the future.
Accounting rules require that we periodically review the carrying value of our proved and unproved properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to significantly write-down the financial carrying value of our oil and natural gas properties, which constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are recorded.
A write-down could occur when oil and natural gas prices are low or if we have substantial downward adjustments to our estimated proved oil and natural gas reserves, or if operating costs or development costs increase over prior estimates.
The capitalized costs of our oil and natural gas properties, on a field-by-field basis, may exceed the estimated future net cash flows of that field. If so, we would record impairment charges to reduce the capitalized costs of such field to our estimate of the field’s fair market value. Unproved properties are evaluated at the lower of cost or fair market value. These types of charges will reduce our earnings and stockholders’ equity and could adversely affect our stock price.
We periodically assess our properties for impairment based on future estimates of proved and non-proved reserves, oil and natural gas prices, production rates and operating, development and reclamation costs based on operating budget forecasts. Once incurred, an impairment charge cannot be reversed at a later date even if price increases of oil and/or natural gas occur and in the event of increases in the quantity of our estimated proved reserves.
If oil, natural gas and NGL prices fall below current levels for an extended period of time and all other factors remain equal, we may incur impairment charges in the future. Such charges could have a material adverse effect on our results of operations for the periods in which they are recorded.
Properties we acquire may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.
Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain and include properties with which we do not have a long operational history. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of a property. We may be required to assume the risk of the physical condition of properties in addition to the risk that they may not perform in accordance with our expectations. If properties we acquire do not produce as projected or have liabilities we were unable to identify, we could experience a decline in our reserves and production, which could adversely affect our business, financial condition and results of operations.
Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions we or other operators may take when drilling, completing, or operating wells that we or they own.
Many of our properties are in reservoirs that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations by us or other operators could cause depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.
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Acquisitions involve a number of risks, including the risk that we will discover unanticipated liabilities or other problems associated with the acquired business or property.
In assessing potential acquisitions, we consider information available in the public domain and information provided by the seller. In the event publicly available data is limited, then, by necessity, we may rely to a large extent on information that may only be available from the seller, particularly with respect to drilling and completion costs and practices, geological, geophysical and petrophysical data, detailed production data on existing wells, and other technical and cost data not available in the public domain. Accordingly, the review and evaluation of businesses or properties to be acquired may not uncover all existing or relevant data, obligations or actual or contingent liabilities that could adversely impact any business or property to be acquired and, hence, could adversely affect us as a result of the acquisition. These issues may be material and could include, among other things, unexpected environmental liabilities, title defects, unpaid royalties, taxes or other liabilities.
The success of any acquisition that we complete will depend on a variety of factors, including our ability to accurately assess the reserves associated with the acquired properties, assumptions related to future oil and natural gas prices and operating costs, potential environmental and other liabilities and other factors. These assessments are often inexact and subjective. As a result, we may not recover the purchase price of a property from the sale of production from the property or recognize an acceptable return from such sales or operations.
Our ability to achieve the benefits that we expect from an acquisition will also depend on our ability to efficiently integrate the acquired operations. Management may be required to dedicate significant time and effort to the integration process, which could divert its attention from other business opportunities and concerns. The challenges involved in the integration process may include retaining key employees and maintaining employee morale, addressing differences in business cultures, processes and systems and developing internal expertise regarding acquired properties.
Our operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which we may conduct oil, natural gas and NGL exploration and production activities, and reduce demand for the oil, natural gas and NGL we produce.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the Clean Air Act, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, impose new standards reducing methane emissions from oil and gas operations through limitations on venting and flaring and the implementation of enhanced emission leak detection and repair requirements, and together with the United States Department of Transportation, implement GHG emissions limits on vehicles manufactured for operation in the United States. The federal regulation of methane emissions from oil and natural gas facilities has been subject to uncertainty in recent years and the EPA is currently proposing new and updated rules for both new and existing sources. The EPA's proposed rules, if finalized would make existing regulations more stringent, expand the scope of source types covered by the rules and require states to develop plans to reduce methane and volatile organic compound emissions from existing sources that must be at least as effective as presumptive standards set by EPA. The EPA is currently seeking public comments on its proposal. However, all of these regulatory actions will likely be subject to legal challenges. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and natural gas industry remain a significant possibility.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates elected to public office. President Biden has issued several executive orders focused on addressing climate change, including items that may impact costs to produce, or demand for, oil and gas. There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into other sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that over 450 firms in the financial sector across 45 countries committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. President Biden signed an executive order calling for the development of a “climate finance plan” and, separately, the Federal Reserve has joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector. In November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.
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Additionally, in March 2022, the SEC issued a proposed rule that would mandate extensive disclosure of climate risks, including financial impacts, related governance and strategy and GHG emissions, for all U.S.-listed public companies. Although the final form and substance of this rule and its requirements are not yet known and its ultimate impact on our business is uncertain, compliance with the proposed rule, if finalized, may result in additional legal, accounting and financial compliance costs.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas. Additionally, political, litigation and financial risks may result in us restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or having an impaired ability to continue to operate in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition and results of operations.
As a final note, climate change could have an effect on the severity of weather (including hurricanes, droughts and floods), sea levels, water availability and quality, and meteorological patterns. If such effects were to occur, our development and production operations have the potential to be adversely affected.
Potential adverse effects could include damages to our facilities from powerful winds, extreme temperatures, or rising waters in low-lying areas, disruption of our production activities either because of climate related damages to our facilities or in our costs of operation potentially arising from such climatic effects, less efficient or non- routine operating practices necessitated by climate effects or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. Additionally, changing meteorological conditions, particularly temperature, may result in changes to the amount, timing, or location of demand for energy or the products we produce. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.
The marketability of our production is dependent upon gathering systems, transportation facilities and processing facilities that we do not own or control. If these facilities or systems are unavailable, our oil and natural gas production can be interrupted and our revenues reduced.
The marketability of our oil and natural gas production is dependent upon the availability, proximity and capacity of pipelines, natural gas gathering systems, transportation and processing facilities owned by third parties. In general, we will not control these facilities, and our access to them may be limited or denied due to circumstances beyond our control. A significant disruption in the availability of these facilities could adversely impact our ability to deliver to market the hydrocarbons we produce and thereby cause a significant interruption in our operations. In some cases, our ability to deliver to market our hydrocarbons is dependent upon coordination among third parties that own transportation and processing facilities we use, and any inability or unwillingness of those parties to coordinate efficiently could also interrupt our operations. The lack of availability or the lack of capacity on these systems and facilities could result in the curtailment of production or the delay or discontinuance of drilling plans. These are risks for which we generally will not maintain insurance.
We operate or participate in oil and natural gas leases with third parties who may not be able to fulfill their commitments to our projects.
In some cases, we operate but own less than 100% of the working interest in the oil and natural gas leases on which we conduct operations, and other parties own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position.
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Because we cannot control activities on properties we do not operate, we cannot directly control the timing of exploitation. If we are unable to fund required capital expenditures with respect to non-operated properties, our interests in those properties may be reduced or forfeited.
Our ability to exercise influence over operations and costs for the properties we do not operate is limited. Our dependence on the operators and other working interest owners for these projects and our limited ability to influence operations and associated costs could prevent the realization of our targeted returns on capital with respect to acquisition, exploration and development activities. The success and timing of development, exploitation and exploration activities on properties operated by others depend upon a number of factors that may be outside our control, including but not limited to the timing and amount of capital expenditures; the operator’s expertise and financial resources; the approval of other participants in drilling wells; and the selection of technology.
Where we are not the majority owner or operator of a particular oil and natural gas project, we may have no control over the timing or amount of capital expenditures associated with the project. If we are not willing or able to fund required capital expenditures relating to a project when required by the majority owner(s) or operator, our interests in the project may be reduced or forfeited. Also, we could be responsible for plugging and abandonment costs, as well as other liabilities in excess of our proportionate interest in the property.
We could be adversely affected by increased costs of service providers utilized by us.
In accordance with customary industry practice, we have relied and will rely on independent third-party service providers to provide most of the services necessary to operate. The industry has experienced significant price fluctuations for these services during the last year and this trend is expected to continue into the future. These cost uncertainties could, in the future, significantly increase our production costs.
Our ability to use our existing net operating loss carryforwards or other tax attributes could be limited.
At December 31, 2022, we had approximately $18.6 million of federal net operating loss (“NOL”) carryforwards generated in prior years that could offset against future taxable income. Utilization of any NOL depends on many factors, including our ability to generate future taxable income, which cannot be assured. In the event that we were to undergo an “ownership change” (as defined in Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”)), our federal NOL carryforwards generated prior to the ownership change would be subject to annual limitations, which could defer or eliminate our ability to utilize these tax losses against future taxable income. Generally, an “ownership change” occurs if one or more stockholders, each of whom owns 5% or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50% over the lowest percentage of stock owned by those stockholders at any time during the preceding three-year period.
Legislation
Climate change legislation, regulations restricting emissions of “greenhouse gases” (GHG’s) or legal or other action taken by public or private entities related to climate change could result in increased operating costs and reduced demand for the oil and natural gas that we produce.
The threat of climate change continues to attract considerable attention in the United States and around the world. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG disclosure obligations and regulations that directly limit GHG emissions from certain sources. Moreover, President Biden highlighted addressing climate change as a priority of his administration, issued several executive orders related to climate change and recommitted the United States to long-term international goals to reduce emissions. In recent years, Congress has considered legislation to reduce emissions of GHGs, including methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas. For example, the Inflation Reduction Act of 2022, which appropriates significant federal funding for renewable energy initiatives and, for the first time, imposes a fee on GHG emissions from certain facilities, was signed into law in August 2022. The emissions fee and funding provisions of the law could increase operating costs within the oil and natural gas industry and accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations.
At the international level, the United Nations ("UN") -sponsored "Paris Agreement" requires member states to submit non-binding, individually-determined reduction goals known as Nationally Determined Contributions every five years after 2020. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the
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United States' emissions by 50 to 52% below 2005 levels by 2030. Additionally, at the UN Climate Change Conference of Parties ("COP26"), held in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including "all feasible reductions" in the energy sector. COP26 concluded with the finalization of the Glasgow Climate Pact, which stated long-term global goals (including those in the Paris Agreement) to limit the increase in the global average temperature and emphasized reductions in GHG emissions. These goals were reaffirmed at the November 2022 Conference of Parties ("COP27"). At COP27, the United States also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. Moreover, various state and local governments have also publicly committed to furthering the goals of the Paris Agreement. The full impact of these actions, and any legislation or regulation promulgated to fulfill the United States' commitments thereunder, is uncertain at this time, and it is unclear what additional initiatives may be adopted or implemented that may have adverse effects upon our operations.
The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Reduced demand for the oil and natural gas that we produce could also have the effect of lowering the value of our reserves. It should also be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and natural gas companies in connection with their GHG emissions. Should we be targeted by any such litigation or investigations, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating factors. The ultimate impact of GHG emissions-related agreements, legislation and measures on our company’s financial performance is highly uncertain because we are unable to predict with certainty, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and tradeoffs that inevitably occur in connection with such processes.
Any change to government regulation or administrative practices may have a negative impact on our ability to operate and our profitability.
Oil and natural gas operations are subject to substantial regulation under federal, state and local laws relating to the exploration for, and the development, upgrading, marketing, pricing, taxation, and transportation of, oil and natural gas and related products and other associated matters. Amendments to current laws and regulations governing operations and activities of oil and natural gas exploration and development operations could have a material adverse impact on our business. In addition, there can be no assurance that income tax laws, royalty regulations and government programs related to our oil and natural gas properties and the oil and natural gas industry generally will not be changed in a manner which may adversely affect our progress or cause delays.
Permits, leases, licenses, and approvals are required from a variety of regulatory authorities at various stages of exploration and development. There can be no assurance that the various government permits, leases, licenses and approvals sought will be granted in respect of our activities or, if granted, will not be cancelled or will be renewed upon expiration. There is no assurance that such permits, leases, licenses, and approvals will not contain terms and provisions which may adversely affect our exploration and development activities.
Other
A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. We are dependent on digital technologies including information systems and related infrastructure, to process and record financial and operating data, communicate with our employees, business partners, and stockholders, analyze 3-D seismic and drilling information, estimate quantities of oil and natural gas reserves as well as other activities related to our business.
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As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber-attack could include gaining unauthorized access to digital systems for the purposes of misappropriating assets or sensitive information, corrupting data, causing operational disruption, or result in denial-of-service on websites.
Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period of time. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, data, facilities and infrastructure may result in increased capital and operating costs. Costs for insurance may also increase as a result of security threats, and some insurance coverage may become more difficult to obtain, if available at all. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations.
The loss or unavailability of any of our executive officers or other key employees could have a material adverse effect on our business.
We depend greatly on the efforts of our executive officers and other key employees to manage our operations. The loss or unavailability of any of our executive officers or other key employees could have a material adverse effect on our business.
We do not expect to declare or pay any dividends in the foreseeable future.
We have not declared or paid any dividends on our common stock. We currently intend to retain future earnings to fund the development and growth of our business, to repay indebtedness and for general corporate purposes, and therefore, do not anticipate paying any cash dividends on our common stock in the foreseeable future.
The price of our common stock may fluctuate significantly, which could negatively affect us and holders of our common stock.
Our common stock trades on the NYSE American. The trading price of our common stock may fluctuate significantly in response to a number of factors, many of which are beyond our control. Adverse events including changes in production volumes, worldwide demand and prices for crude oil and natural gas, regulatory developments, and changes in any securities analysts’ estimates of our financial performance could negatively impact the market price of our common stock. General market conditions, including the level of, and fluctuations in, the trading prices of stocks generally could also have a similar negative impact. The stock markets regularly experience price and volume volatility that affects many companies’ stock prices without regard to the operating performance of those companies. Volatility of this type may affect the trading price of our common stock.
Provisions of our certificate of incorporation and bylaws and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for our common stock.
Provisions in our certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of us or a merger in which we are not the surviving company and may otherwise prevent or slow changes in our board of directors and management. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the General Corporation Law of the State of Delaware, which provides certain restrictions on business combinations involving interested parties. These provisions could discourage an acquisition of us or other change in control transactions and thereby negatively affect the price that investors might be willing to pay in the future for our common stock.
Holders of our outstanding Series A Voting Preferred Stock have effective control of our board of directors.
We have six shares of Series A Voting Preferred Stock currently issued and outstanding. The Series A Voting Preferred Stock was issued in connection with the strategic investment in us by Energy Evolution (Master Fund), Ltd. (the “Fund”). For so long as the Series A Voting Preferred Stock is outstanding, our board of directors will consist of six directors. Three of the directors are designated as the Series A Directors and the three other directors (each, a “common director”) are elected by the holders of
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common stock and/or any preferred stock (other than the Series A Voting Preferred Stock) granted the right to vote on the common directors. Any Series A Director may be removed with or without cause but only by the affirmative vote of the holders of a majority of the Series A Voting Preferred Stock voting separately and as a single class. The holders of the Series A Voting Preferred Stock have the exclusive right, voting separately and as a single class, to vote on the election, removal and/or replacement of the Series A Directors. Holders of common stock or other preferred stock have no right to vote on the Series A Directors. In addition, in the case of any tie vote or deadlock of the board of directors, our current Chairman of the Board, a Series A Director, has the deciding, tiebreaking vote. Accordingly, the holder(s) of our Series A Voting Preferred Stock have effective control of our board of directors for so long as the voting rights of the Series A Voting Preferred Stock remain in effect.
Our bylaws provide that the Court of Chancery of the State of Delaware (or if the Court of Chancery does not have jurisdiction, the federal district court for the District of Delaware) will be the exclusive forum for certain legal actions between us and our stockholders. These provisions could increase costs to bring a claim, discourage claims or limit the ability of our stockholders to bring a claim in a judicial forum viewed by the stockholders as more favorable for disputes with us or our directors, officers or employees.
Our bylaws provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware (or if the Court of Chancery does not have jurisdiction, the federal district court for the District of Delaware) will be the sole and exclusive forum for (a) any derivative action or proceeding brought on our behalf, (b) any action asserting a claim of breach of a fiduciary duty owed by any director, officer, stockholder, employee or agent to us or our stockholders, (c) any action asserting a claim arising pursuant to any provision of the General Corporation Law of the State of Delaware, our certificate of incorporation or our bylaws, or (d) any action asserting a claim governed by the internal affairs doctrine, in each case subject to the court having personal jurisdiction over the defendants. This exclusive forum provision is intended to apply to claims arising under Delaware state law and is not intended to apply to claims arising under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended. The choice of forum provisions may increase costs to bring a claim, discourage claims or limit a stockholder's ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers or employees, which may discourage such lawsuits against us or our directors, officers and employees. Alternatively, if a court were to find the choice of forum provision contained in our bylaws to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
ITEM 2. PROPERTIES.
Information regarding our properties is included in Item 1 above and in our consolidated financial statements, which is incorporated herein by reference.
ITEM 3. LEGAL PROCEEDINGS.
In the ordinary course of business, we may be involved in litigation and claims arising from operations. As of December 31, 2022, and through the filing date of this Annual Report on Form 10-K, management does not believe the ultimate resolution of any such actions or potential actions of which management is currently aware will have a material effect on our consolidated financial position or results of operations.
ITEM 4. MINE SAFETY DISCLOSURES.
Not applicable.
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PART II
| ITEM 5. | MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES. |
Market Information
Our common stock is traded on the NYSE American under the symbol "EP".
Stockholders
At March 31, 2023, there were approximately 900 stockholders of record of our common stock.
Dividends
We have never paid cash dividends on our common stock. We intend to retain future earnings for use in our business and, therefore, do not anticipate paying cash dividends on our common stock in the foreseeable future. Future payment of dividends will depend upon, but not be limited to, our financial condition, funds available for operations, the amount of anticipated capital and other expenditures, future business prospects and any restrictions imposed by present or future financing arrangements.
Issuer Repurchase of Equity Securities
No private or open market repurchases of common stock were made by us during the fourth quarter of 2022.
Unregistered Sales of Equity Securities
No such sales that have not been previously reported on a Quarterly Report on Form 10-Q or a Current Report on Form 8-K.
ITEM 6. RESERVED.
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| ITEM 7. | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. |
The following discussion should be read together with the consolidated financial statements and notes to consolidated financial statements, which are included in this Annual Report on Form 10-K in Item 8, Financial Statements and Supplementary Data, and the information set forth in Part I, Item 1A – Risk Factors.
Overview
Our primary business is the exploration and development of oil and gas interests. We have incurred significant losses from operations in years prior to 2022, and there is no assurance that we will maintain profitability or obtain funds necessary to finance our future operations.
We seek to increase shareholder value by growing reserves, production, revenues, and cash flow from operating activities by executing our mission to use highly-skilled personnel to thoughtfully and expertly spend capital to realize reserves on producing properties.
Management places emphasis on operating cash flow in managing our business, as operating cash flow considers the cash expenses incurred during the period and excludes non-cash expenditures not related directly to our operations.
Business Strategy
Our business strategy is to obtain long-term growth in reserves and cash flow on a cost-effective basis. Management regularly evaluates potential acquisitions of properties that would enhance current core areas of operation.
2021 XTO Acquisition
On March 12, 2021, the Company, through its wholly owned subsidiary Empire New Mexico, entered into a purchase and sale agreement with XTO Holdings, LLC (a subsidiary of ExxonMobil) to acquire, among other things, certain oil and natural gas properties in New Mexico. The transaction closed in May 2021. For more information about the transaction, refer to Note 4 of our Consolidated Financial Statements included in this report.
Results of Operations
The following table reflects our summary operating information. Because of normal production declines, increased or decreased drilling activity and the effects of acquisitions, the historical information presented below should not be interpreted as indicative of future results.
| Years Ended December 31, | ||||||||||||||||
| 2022 | 2021 | $ Variance | Variance % | |||||||||||||
| Oil revenues | $ | 44,978,554 | $ | 22,326,289 | 22,652,265 | 101% | ||||||||||
| Natural gas revenues | 4,534,370 | 2,288,481 | 2,245,889 | 98% | ||||||||||||
| NGL revenues | 3,659,451 | 2,888,747 | 770,704 | 27% | ||||||||||||
| Total product revenues | 53,172,375 | 27,503,517 | ||||||||||||||
| Lease operating expense | 23,584,039 | 13,283,758 | 10,300,281 | 78% | ||||||||||||
| Production and ad valorem taxes | 3,943,466 | 2,102,772 | 1,840,694 | 88% | ||||||||||||
| Depreciation, depletion, amortization and accretion | 3,307,097 | 3,716,754 | (409,657 | ) | -11% | |||||||||||
| Impairment | 936,620 | — | 936,620 | NM | ||||||||||||
| General and administrative expense (excluding stock-based compensation) | 9,614,948 | 7,366,061 | 2,248,887 | 31% | ||||||||||||
| Stock-based compensation | 2,716,541 | 1,095,970 | 1,620,571 | 148% | ||||||||||||
| Cash-based interest expense | 473,205 | 436,053 | 37,152 | 9% | ||||||||||||
| Non-cash interest expense | 36,335 | 8,164,646 | (8,128,311 | ) | -100% | |||||||||||
| Operating Income (Loss) | 8,784,163 | (473,370 | ) | 9,257,533 | -1956% | |||||||||||
| Net Income (Loss) | 7,084,130 | (18,614,962 | ) | 25,699,092 | NM | |||||||||||
NM: A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
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Revenues
Revenues increased primarily as a result of higher volumes due to a full year impact of the XTO acquisition as well as higher commodity prices in 2022. Average realized oil price in 2022 was approximately $93 per barrel, while average realized price in 2021 was approximately $67, an increase in price of approximately 39%. Realized natural gas price for 2022 was approximately $5.18 per Mcf, while realized pricing for 2021 was approximately $3.68 per Mcf, an increase in price of approximately 41%. Net oil volumes were approximately 483,000 Bbls for 2022, an increase of 45% over the same period in the prior year. Net natural gas volumes were approximately 876,000 Mcf for 2022 as compared to approximately 622,000 for 2021, an increase of approximately 41%. NGL revenues are primarily from our New Mexico properties acquired from XTO.
Lease Operating Expense and Production Taxes
Lease operating expense was higher in 2022 primarily as a result of a full year of operations in New Mexico after the May 2021 XTO acquisition. Lease operating expenses for New Mexico were approximately $5.1 million more in 2022 than for 2021. Production and ad valorem taxes have increased as a direct result of the XTO acquisition’s properties and increased volumes produced and sold, paired with higher realized prices. In addition to recompletions and sidetrack well drilling activity in North Dakota, we also undertook workover and other lease operating activities in 2022; North Dakota’s lease operating expenses increased by approximately $3.3 million period-over-period as a result of increased field activity.
Depreciation, Depletion, Amortization and Accretion and Impairment
DD&A decreased in 2022 as compared to 2021 despite an increase in production volumes. The decrease in the expense is primarily related to New Mexico depletion rate due to the impact of a higher reserve base in 2022. Accretion expense was slightly higher in 2022 as the overall obligation increases over time.
We assess our oil and gas properties for impairment when circumstances indicate the carrying value may be greater than its estimated future net cash flows. In 2022, estimated future cash flows from our properties in Louisiana were less than the net book value. As a result, we recorded a $936,000 impairment expense.
General and Administrative Expense
Board compensation expense, exclusive of stock-based compensation, was approximately $388,000 in 2022 as compared to $209,000 in 2021. Overall personnel expense increased approximately $500,000 in 2022 over 2021. In 2022, we recognized expenses totaling approximately $1,269,000 in conjunction with resolution of a Texas sales tax audit for prior periods for which the initial assessment was received in April 2022. This total includes consulting fees and an accrual for $528,000 for the final settlement which will be paid in early 2023. Fees paid for professional services including outsourced services and legal increased over 2021 by approximately $500,000 as a direct result of acquisition-related work, SEC filings related to our operations, and our successful uplisting from the OTCQB to the NYSE American. Included in general and administrative expenses for 2021 is $989,000 for expense associated with a non-cash right to buy shares in conjunction with the conversion of unsecured notes payable in 2021 as discussed in Note 9 to the Consolidated Financial Statements included in this report.
Stock-based Compensation
We utilize stock-based compensation to compensate members of management and retain talented personnel. Our stock-based compensation increased in 2022 due to a higher number of awards in 2022. We anticipate stock-based compensation to continue to be utilized in 2023 and beyond to attract and retain talented personnel and compensate Board members and consultants.
Interest Expense
Cash-based interest expense increased slightly as a decrease due to a lower outstanding balance under our Credit Facility was offset by the impact of higher interest rates. We have minimal interest-bearing vehicle and equipment notes payable.
Non-cash interest expense is fully attributable to the related party notes payable as described in Note 9 to the Consolidated Financial Statements included in this report. In 2021, a non-cash charge was recorded to interest expense of approximately $7.0 million related to interest and amortization of debt issuance costs for convertible notes issued in 2021 that were fully converted prior to December 31, 2021.
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Income taxes
For 2022, we had income before income taxes which would result in a tax provision that was offset by a change in the valuation allowance due to the anticipated use of the NOL carryforward. For periods prior to 2022, our effective tax rate is 0%. Due to having current taxable income which cannot be fully offset by NOLs, the tax rate is 3% in 2022. We have generated net operating losses since inception, which would normally reflect a tax benefit in the consolidated statement of operations and a deferred asset on the consolidated balance sheet. However, because of the current uncertainty as to our ability to achieve sustained profitability and the potential limitation of NOL carryforwards, a valuation reserve has been established that offsets the amount of any tax benefit available for each period presented in the consolidated statements of operations.
Liquidity
As of December 31, 2022, we had approximately $12 million cash on hand and approximately $300,000 available on the Credit Facility. For additional information regarding the Credit Facility, see Note 8 to the Consolidated Financial Statements included in this report. We expect to incur costs related to limited drilling activities in core areas as well as future oil and natural gas acquisitions. It is expected that management will use a combination of cash on hand and cash flows from operations as well as seeking additional debt or equity funding for these acquisitions and to fund ongoing operations.
Working Capital
Working capital (presented below) was $5.1 million as of December 31, 2022 compared to $1.1 million as of December 31, 2021, representing a change of approximately $4.0 million. This change is primarily a result of the acquisition of producing properties in New Mexico, which served to increase volumes sold for the year ended December 31, 2022, as well as the stronger pricing environment in 2022.
| As of December 31, | ||||||||
| 2022 | 2021 | |||||||
| Current Assets | $ | 22,734,973 | $ | 13,118,020 | ||||
| Current Liabilities | $ | 17,620,660 | $ | 12,054,487 | ||||
| Working Capital | $ | 5,114,313 | $ | 1,063,533 | ||||
Cash Flows
| Year Ended December 31, | ||||||||||||
| Cash flows provided by (used in): | 2022 | 2021 | Variance | |||||||||
| Operating activities | $ | 18,055,783 | $ | 3,170,282 | $ | 14,885,501 | ||||||
| Investing activities | (11,413,487 | ) | (24,716,878 | ) | 13,303,391 | |||||||
| Financing activities | 1,690,275 | 25,000,772 | (23,310,497 | ) | ||||||||
Cash Flows from Operating Activities
Ongoing operations from core assets contributed to cash flows provided by operating activities for the year ended December 31, 2022. In 2021, we incurred approximately $18.0 million in non-cash expenses related to the convertible notes payable (See Related Party Transactions for more information) that contributed to a net loss for financial reporting purposes.
Cash Flows from Investing Activities
Cash flows from investing activities in 2022 reflect $2.7 million related to acquisitions of oil and natural gas properties as compared to $19.5 million in 2021 which primarily related to the XTO acquisition that occurred in May 2021. In 2022, we began recompletions and other capitalizable efforts in multiple states as we sought to bring production online from existing wells and bring on new production from sidetrack drilling in North Dakota which led to an increase in additions to oil and natural gas properties in 2022. We also participated in the drilling of four non-operated wells through Empire Rockies Region in 2022 spending approximately $600,000. In 2021, we had a cash outflow of approximately $2.5 million related to four other non-operated drilled wells. As part of the XTO acquisition, we entered into an agreement to create a sinking fund for future plugging liabilities, paying approximately $4.8 million into that fund in 2021. In 2022, we were able to negotiate for the release of the sinking fund requirement. Approximately $2 million of the sinking fund balance was returned to us in 2022.
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Cash Flows from Financing Activities
In 2022, we received approximately $3.4 million in cash from warrant exercises. We also made approximately $1.2 million of principal payments in 2022 on our Credit Facility. In 2021, the XTO acquisition and operations executing our mission were funded by proceeds from debt issued of approximately $20.5 million as well as proceeds from stock and warrant issuances of approximately $11.3 million. We have quarterly payment obligations related to our bank debt of $300,000 per quarter (increased to $500,000 per quarter in 2023) in addition to minimal monthly payments for notes payable arising from the purchase of vehicles and equipment.
Capital Resources
Capital Expenditures
For 2022, additions to oil and natural gas properties totaled $14.6 million including $2.7 million related to acquisitions. The $11.9 million not related to acquisitions primarily reflects well enhancement projects in North Dakota and non-operated drilling. We anticipate capital expenditures in 2023 that will be funded with cash on hand, cash flows from operations, debt, and/or equity issuances.
Related Party Transactions
The 2021 issuance of a secured convertible note and an unsecured convertible note to Energy Evolution, a related party, as well as the conversion of these notes in 2021 are described further in Note 9 to the Consolidated Financial Statements included in this report. These transactions were related party transactions for accounting purposes.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Critical Accounting Estimates
The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosures of contingent assets and liabilities. Because estimates and assumptions require significant judgment, future actual results could differ from those estimates and could have a significant impact on our results of operations, financial position and cash flows. We re-evaluate our estimates and assumptions at least on a quarterly basis. In our management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are as follows:
Successful Efforts Method of Accounting for Oil and Natural Gas Activities
We use the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire oil and natural gas properties, drill successful exploratory wells, drill and equip development wells, and install production facilities are capitalized. Estimated proved oil and natural gas reserves, management’s outlook on commodity prices and projected future cash flows of oil and natural gas reserves are a significant part of our financial calculations. Following are examples of how these estimates affect financial results:
| • | an increase (decrease) in estimated proved oil, natural gas and NGL reserves can reduce (increase) our unit-of-production depletion and amortization rates; and |
| • | changes in the oil, natural gas and NGL reserves and the projected future cash flows from our properties can impact our periodic impairment analyses. |
Proved oil and natural gas reserves are the estimated quantities of oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Reserve quantities and future cash flows included in this report are prepared in accordance with guidelines established by the SEC and the Financial Accounting Standards Board (“FASB”). The accuracy of reserve estimates is a function of:
| • | The quality and quantity of available data; |
| • | The interpretation of that data; |
| • | The accuracy of various mandated economic assumptions; and |
| • | The judgments of the persons preparing the estimates. |
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Proved reserves information included in this report is based on estimates prepared by independent petroleum engineers, Cawley Gillespie &Associates. The independent petroleum engineers evaluated 100% of our estimated proved producing reserve quantities and their related future net cash flows as of December 31, 2022. Estimates prepared by others may be higher or lower than these estimates. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. Management may make revisions to reserve estimates throughout the year as additional information becomes available. Such changes could trigger an impairment of our oil and natural gas properties and have an impact on our depletion expense prospectively. For example, a change of 10 percent in our total proved reserves could change our annual depletion and amortization expense by $200,000. The actual impact would depend on the specific areas impacted.
Impairment of Oil and Gas Properties
We assess our proved properties for impairment using estimates of future undiscounted cash flows. This assessment requires significant judgment and assumptions including commodity price outlooks, estimates of reserve quantities, expected lease operating costs and capital costs. An impairment expense could result if oil and gas prices decline in the future as it may not be economic to develop some of these unproved properties. We performed an assessment as of December 31, 2022 and identified one area that was impaired and recorded an impairment in 2022 of $936,000.
Asset Retirement Obligation
Asset retirement obligations (“AROs”) consist primarily of estimated future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage, and land restoration in accordance with applicable local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. The recognition of an ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; inflation rates; and future advances in technology. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows.
Stock-Based Compensation
We recognize stock-based compensation expense associated with restricted stock units, which consists of time-based awards and options. We account for forfeitures of equity-based incentive awards as they occur. Stock-based compensation expense related to time-based restricted stock units is based on the price of our common stock on the grant date. Stock-based compensation related to options is the fair value of the option recognized over the vesting period. The fair value of an option is determined using the Black-Scholes option valuation with the following assumption inputs: dividend yield, expected annual volatility risk free interest rate and an expected life.
Income Taxes and Uncertain Tax Positions
Our tax provision is based upon the tax laws and rates in effect in the applicable jurisdiction in which operations are conducted and income is earned. As part of the process of preparing the consolidated financial statements, management is required to estimate the income tax provision. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, amortization and certain accrued liabilities for tax and accounting purposes.
Deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. At December 31, 2022 and 2021, a valuation allowance for deferred tax assets was recorded.
Management applies the accounting standards related to uncertainty in income taxes. This accounting guidance clarifies the accounting for uncertainties in income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the consolidated financial statements. It requires that we recognize in the consolidated financial statements the financial effects of a tax position, if that position is more likely than not of being sustained upon examination, including resolution of any appeals or litigation processes, based upon the technical merits of the position. It also provides guidance on measurement, classification, interest, penalties and disclosure. We have no uncertain tax positions at either December 31, 2022 or December 31, 2021.
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| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. |
We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide this information.
| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. |
The financial statements of the Company are set forth at the end of this Form 10-K.
| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. |
None.
| ITEM 9A. | CONTROLS AND PROCEDURES. |
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, the Company carried out an evaluation under the supervision and participation of the Company’s Principal Executive Officer and Principal Financial Officer, along with our management, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as defined in Exchange Act Rule 13a-15(e). Based on this evaluation, the Company’s Principal Executive Officer and Principal Financial Officer concluded that the disclosure controls and procedures as of the end of the period covered by this report are not effective due to a material weakness identified below.
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Under the supervision and with the participation of the Company’s management, including its Principal Executive Officer and Principal Financial Officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework established by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) as set forth in Internal Control - Integrated Framework. Based on our evaluation under that framework, our management concluded that our internal control over financial reporting was not effective as of December 31, 2022, due to a material weakness.
A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a possibility that a material misstatement in our financial statements will not be prevented or detected on a timely basis. In the prior year, a material weakness in internal control application was discovered related to the internal controls over financial reporting, including disclosures around complex and non-routine transactions. Management believes the Company’s lack of sufficient accounting personnel with appropriate accounting expertise to appropriately apply GAAP for complex and non-routine transactions and prepare associated financial statement disclosures amounts to a material weakness in its internal control over financial reporting.
As a result, at December 31, 2022 and on the date of this Report, its internal control over financial reporting is not effective.
Management’s Plan to Remediate the Material Weakness
Management has evaluated the material weakness described above and is in the process of updating its design and implementation of internal control over financial reporting to remediate the aforementioned material weakness and enhance the Company’s internal control environment which to date has included the hiring of a Chief Accounting Officer in October 2021. In the first quarter of 2022, the Chief Accounting Officer engaged an outside company to undertake an internal controls review. This review concluded in the third quarter of 2022. Controls that would strengthen the Company’s internal control structure that were identified during the course of the review continue to be designed and will be implemented on an ongoing basis. In December 2022, we had a change in the Chief Accounting
| -29- |
Officer although the former Chief Accounting Officer has continued to assist the Company on a part-time basis. In addition to continuing to enhance and refine control design, management plans to add the appropriate resources and focus efforts during 2023 to test the operational effectiveness of the controls that will be established. We are committed to continuing to improve our internal control processes and will continue to diligently and vigorously review our financial reporting controls and procedures.
Changes in Internal Controls over Financial Reporting
While we continue to implement design enhancements to our internal control procedures, we believe that, other than the changes described above regarding the ongoing remediation efforts, there were no changes to our internal control over financial reporting which were identified in connection with the evaluation required by Rules 13a-15(d) or 15d-15(d) under the Exchange Act during the fourth quarter of 2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Attestation Report of Registered Public Accounting Firm
This Annual Report does not contain an attestation report of our independent registered public accounting firm related to internal control over financial reporting because the rules for smaller reporting companies provide an exemption from the attestation requirement.
| ITEM 9B. | OTHER INFORMATION. |
None.
| ITEM 9C. | DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS. |
Not applicable.
| -30- |
PART III
| ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE. |
The information called for by this Item 10 is incorporated herein by reference to our definitive Proxy Statement for 2023 annual meeting of stockholders (“2023 Proxy Statement”) to be filed with the SEC no later than 120 days following the fiscal year ended December 31, 2022.
| ITEM 11. | EXECUTIVE COMPENSATION. |
The information called for by this Item 11 is incorporated herein by reference to our 2023 Proxy Statement to be filed with the SEC no later than 120 days following the fiscal year ended December 31, 2022.
| ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS. |
The information called for by this Item 12 is incorporated herein by reference to our 2023 Proxy Statement to be filed with the SEC no later than 120 days following the fiscal year ended December 31, 2022.
| ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE. |
The information called for by this Item 13 is incorporated herein by reference to our 2023 Proxy Statement to be filed with the SEC no later than 120 days following the fiscal year ended December 31, 2022.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
The information called for by this Item 14 is incorporated herein by reference to our 2023 Proxy Statement to be filed with the SEC no later than 120 days following the fiscal year ended December 31, 2022.
| -31- |
PART IV
| ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES. |
| (a) | (1) Financial Statements |
The financial statements under this item are included in Item 8 of Part II of this Annual Report on Form 10-K.
| (2) Schedules | |
| NONE |
| (3) Exhibits |
| -32- |
| -33- |
*Indicates a management contract or compensatory plan or arrangement identified under the requirements of Item 15 of Form 10-K.
| ITEM 16. | FORM 10-K SUMMARY. |
None.
| -34- |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Empire Petroleum Corporation
|
|||
| Date: March 31, 2023 | By: | /s/ Michael R. Morrisett | |
| Name: Michael R. Morrisett | |||
| Title: President and Chief Executive Officer | |||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Signature | Title | Date | ||
| /s/ Michael R. Morrisett | Director, President and Chief Executive Officer | March 31, 2023 | ||
| MICHAEL R. MORRISETT | (Principal Executive Officer and Principal Financial Officer) | |||
| /s/ Stephen L Faulkner | Chief Accounting Officer | March 31, 2023 | ||
| STEPHEN L. FAULKNER | (Principal Accounting Officer) | |||
| /s/ Phil E. Mulacek | Director and Chairman of the Board | March 31, 2023 | ||
| PHIL E. MULACEK | ||||
| /s/ Andrew Lewis | Director | March 31, 2023 | ||
| ANDREW LEWIS | ||||
| /s/ Mason H. Matschke | Director | March 31, 2023 | ||
| MASON H. MATSCHKE | ||||
| /s/ Benjamin J. Marchive II | Director | March 31, 2023 | ||
| BENJAMIN J. MARCHIVE II | ||||
| -35- |
EMPIRE PETROLEUM CORPORATION
CONSOLIDATED FINANCIAL STATEMENTS
CONTENTS
| Page No. | |
| Report of Independent Registered Public Accounting Firm – Grant Thornton LLP (PCAOB ID Number 248) | 37 |
| Report
of Independent Registered Public Accounting Firm – Moss Adams LLP (PCAOB ID Number |
38 |
| Consolidated Balance Sheets as of December 31, 2022 and 2021 | 39 |
| Consolidated Statements of Operations for the years ended December 31, 2022 and 2021 | 40 |
| Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 2022 and 2021 | 41 |
| Consolidated Statements of Cash Flows for the years ended December 31, 2022 and 2021 | 42 |
| Notes to Consolidated Financial Statements | 43 |
| -36- |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Empire Petroleum Corporation
Opinion on the financial statements
We have audited the accompanying consolidated balance sheet of Empire Petroleum Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2022, the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for the year ended December 31, 2022, 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, 2022, and the results of its operations and its cash flows for the year ended December 31, 2022, 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 audit. 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether 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 audit 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 audit 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 audit 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 audit provides a reasonable basis for our opinion.
Critical audit matters
Critical audit matters are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. We determined there are no critical audit matters.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2022.
Tulsa, Oklahoma
March 31, 2023
| -37- |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and the Board of Directors of
Empire Petroleum Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheet of Empire Petroleum Corporation and subsidiaries (the “Company”) as of December 31, 2021, the related consolidated statements of operations, stockholders’ equity and cash flows for the year then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2021, and the consolidated results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audit. 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion.
/s/
March 31, 2022
We served as the Company’s auditor from 2021 to 2022.
| -38- |
EMPIRE PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
| As of December 31, | ||||||||
| 2022 | 2021 | |||||||
| ASSETS | ||||||||
| Current Assets: | ||||||||
| Cash | $ | $ | ||||||
| Accounts Receivable | ||||||||
| Derivative Instruments | ||||||||
| Inventory - Oil in Tanks | ||||||||
| Prepaids | ||||||||
| Total Current Assets | ||||||||
| Property and Equipment: | ||||||||
| Oil and Natural Gas Properties, Successful Efforts | ||||||||
| Less: Accumulated Depreciation, Depletion and Impairment | ( | ) | ( | ) | ||||
| Total Oil and Gas Properties, Net | ||||||||
| Other Property and Equipment, Net | ||||||||
| Total Property and Equipment, Net | ||||||||
| Derivative Instruments - Long Term | ||||||||
| Sinking Fund | ||||||||
| Utility and Other Deposits | ||||||||
| Total Assets | $ | $ | ||||||
| LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||
| Current Liabilities: | ||||||||
| Accounts Payable | $ | $ | ||||||
| Accrued Expenses | ||||||||
| Current Portion of Lease Liability | ||||||||
| Current Portion of Long-Term Debt | ||||||||
| Total Current Liabilities | ||||||||
| Long-Term Debt | ||||||||
| Long-Term Note Payable - Related Party (Note 5 and 9) | ||||||||
| Long Term Lease Liability | ||||||||
| Asset Retirement Obligations | ||||||||
| Total Liabilities | ||||||||
| Commitments and Contingencies (Note 16) | ||||||||
| Stockholders' Equity: | ||||||||
| Series A Preferred Stock - $ Par Value, Shares Authorized, and Shares Issued and Outstanding, Respectively |
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| Common Stock - $ Par Value Shares Authorized, and Shares Issued and Outstanding, Respectively |
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| Additional Paid-in Capital | ||||||||
| Accumulated Deficit | ( | ) | ( | ) | ||||
| Total Stockholders' Equity | ||||||||
| Total Liabilities and Stockholders' Equity | $ | $ | ||||||
See accompanying notes to consolidated financial statements.
| -39- |
EMPIRE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
| Year Ended December 31, | ||||||||
| 2022 | 2021 | |||||||
| Revenue: | ||||||||
| Oil Sales | $ | $ | ||||||
| Gas Sales | ||||||||
| NGL Sales | ||||||||
| Total Product Revenues | ||||||||
| Other | ||||||||
| Gain (Loss) on Derivatives | ( | ) | ( | ) | ||||
| Total Revenue | ||||||||
| Costs and Expenses: | ||||||||
| Lease Operating Expense | ||||||||
| Production and Ad Valorem Taxes | ||||||||
| Depletion, Depreciation & Amortization | ||||||||
| Accretion of Asset Retirement Obligation | ||||||||
| Impairment | ||||||||
| General and Administrative | ||||||||
| Total Cost and Expenses | ||||||||
| Operating Income (Loss) | ( | ) | ||||||
| Other Income and (Expense): | ||||||||
| Other Income (Expense) | ( | ) | ||||||
| Interest Expense | ( | ) | ( | ) | ||||
| Convertible Debt Modification Inducement Expense | ( | ) | ||||||
| Loss on Convertible Debt Redemption Option | ( | ) | ||||||
| Loss on Embedded Conversion Option | ( | ) | ||||||
| Income (Loss) before Taxes | ( | ) | ||||||
| Income Tax Provision | ( | ) | ||||||
| Net Income (Loss) | $ | $ | ( | ) | ||||
| Net Income (Loss) per Common Share: | ||||||||
| Basic | $ | $ | ( | ) | ||||
| Diluted | $ | $ | ( | ) | ||||
| Weighted Average Number of Common Shares Outstanding: | ||||||||
| Basic | ||||||||
| Diluted | ||||||||
See accompanying notes to consolidated financial statements.
| -40- |
EMPIRE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
Years ended December 31, 2022 and 2021
| Common Stock | Preferred Stock | Additional | ||||||||||||||||||||||||||
| Shares | Par Value | Shares | Par Value | Paid in Capital | Accumulated Deficit | Total | ||||||||||||||||||||||
| Balances, December 31, 2020 | $ | $ | $ | $ | ( | ) | $ | ( | ) | |||||||||||||||||||
| Net Loss | — | — | ( | ) | ( | ) | ||||||||||||||||||||||
| Stock Compensation Expense | — | |||||||||||||||||||||||||||
| Stock Options Exercised | — | |||||||||||||||||||||||||||
| Warrants Exercised | — | |||||||||||||||||||||||||||
| Issuance of Common Stock and Warrants | — | |||||||||||||||||||||||||||
| Shares and Warrants Issued for Secured Convertible Note | — | |||||||||||||||||||||||||||
| Warrants Issued with Unsecured Convertible Notes | — | — | ||||||||||||||||||||||||||
| Right to Buy Issued with Secured Convertible Notes | — | — | ||||||||||||||||||||||||||
| Unsecured Convertible Note Conversion | — | |||||||||||||||||||||||||||
| Shares Issued for Secured Convertible Note Conversion, Including Payment of Accrued Interest | — | |||||||||||||||||||||||||||
| Balances, December 31, 2021 | $ | $ | $ | $ | ( | ) | $ | |||||||||||||||||||||
| Net Income | — | — | ||||||||||||||||||||||||||
| Issuance of Preferred Stock | — | |||||||||||||||||||||||||||
| Stock Compensation Expense | — | — | ||||||||||||||||||||||||||
| Options and Warrants Exercised | — | |||||||||||||||||||||||||||
| Balances, December 31, 2022 | $ | $ | $ | $ | ( | ) | $ | |||||||||||||||||||||
See accompanying notes to consolidated financial statements.
| -41- |
EMPIRE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Year Ended December 31, | ||||||||
| 2022 | 2021 | |||||||
| Cash Flows From Operating Activities: | ||||||||
| Net Income (Loss) | $ | $ | ( | ) | ||||
| Adjustments to Reconcile Net Income (Loss) to Net Cash Provided By Operating Activities: |
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| Stock Compensation and Issuances | ||||||||
| Amortization of Right of Use Assets | ||||||||
| Depreciation, Depletion and Amortization | ||||||||
| Accretion of Asset Retirement Obligation | ||||||||
| Impairment | ||||||||
| Loss on Settlement of Asset Retirement Obligation | ||||||||
| Loss on XTO Final Settlement (See Note 4) | ||||||||
| PIE-Related Expense (See Note 5) | ||||||||
| Amortization of Loan Issue Costs | ||||||||
| Right to Buy Issuance Costs | ||||||||
| Loss on Embedded Conversion Option | ||||||||
| Amortization of Discount on Convertible Notes | ||||||||
| Loss on Extinguishment of Debt | ||||||||
| Convertible Debt Modification Inducement Expense | ||||||||
| Stock Issued for Interest Expense Payment | ||||||||
| Forgiveness of Payroll Protection Plan Loan | ( | ) | ||||||
| Change in Operating Assets and Liabilities: | ||||||||
| Accounts Receivable | ( | ) | ( | ) | ||||
| Derivative Instruments | ( | ) | ||||||
| Inventory, Oil in Tanks | ( | ) | ( | ) | ||||
| Prepaids, Current | ( | ) | ||||||
| Other Long Term Assets and Liabilities | ( | ) | ( | ) | ||||
| Accounts Payable | ||||||||
| Accrued Expenses | ||||||||
| Net Cash Provided By Operating Activities | ||||||||
| Cash Flows from Investing Activities: | ||||||||
| Acquisition of Oil and Natural Gas Properties | ( | ) | ( | ) | ||||
| Additions to Oil and Natural Gas Properties | ( | ) | ||||||
| Purchase of Other Fixed Assets | ( | ) | ( | ) | ||||
| Cash Paid for Right of Use Assets | ( | ) | ( | ) | ||||
| Sinking Fund Deposit | ( | ) | ||||||
| Net Cash Used In Investing Activities | ( | ) | ( | ) | ||||
| Cash Flows from Financing Activities: | ||||||||
| Proceeds from Debt Issued | ||||||||
| Principal Payments of Debt | ( | ) | ( | ) | ||||
| Proceeds from Stock and Warrant Issuances | ||||||||
| Proceeds from Option and Warrant Exercise | ||||||||
| Paycheck Protection Program Loan Proceeds | ||||||||
| Net Cash Provided By Financing Activities | ||||||||
| Net Change in Cash | ||||||||
| Cash - Beginning of Period | ||||||||
| Cash - End of Period | $ | $ | ||||||
| Supplemental Cash Flow Information: | ||||||||
| Cash Paid for Interest | $ | $ | ||||||
| Non-Cash Investing and Financing Activities: | ||||||||
| Non-Cash Additions and Revisions to Asset Retirement Obligations | $ | $ | ||||||
| Right-of-use assets purchased with lease liability | $ | $ | ||||||
| Note Payable Activity - PIE Agreement (see Note 5) | $ | $ | ||||||
| Purchases of Oil and Natural Gas Properties in Accounts Payable | $ | $ | ||||||
| Property Additions in Notes Payable | $ | $ | ||||||
| Common Stock Issued in Exchange for Outstanding Notes Payable | $ | $ | ||||||
| Equipment Purchased Utilizing Note Payable | $ | $ | ||||||
See accompanying notes to consolidated financial statements.
| -42- |
EMPIRE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Organization and Basis of Presentation
Empire Petroleum Corporation (the “Company”, collectively with its subsidiaries) is an independent energy company operator engaged in optimizing developed production by employing field management methods to maximize reserve recovery while minimizing costs. Empire operates the following wholly-owned subsidiaries in its areas of operations:
| ● | Empire New Mexico, LLC (“Empire New Mexico”) | |
| ● | Empire Rockies Region |
| o | Empire North Dakota LLC (“Empire North Dakota”) | |
| o | Empire North Dakota Acquisition LLC (“Empire NDA”) |
| ● | Empire Texas (“Empire Texas”), consisting of the following entities: |
| o | Empire Texas LLC |
| o | Empire Texas Operating LLC | |
| o | Empire Texas GP LLC |
| o | Pardus Oil & Gas Operating, LP (owned 1% by Empire Texas GP LLC and 99% by Empire Texas LLC) |
| ● | Empire Louisiana LLC (“Empire Louisiana”) |
Empire was incorporated in the State of Delaware in 1985. The consolidated financial statements of Empire Petroleum Corporation and subsidiaries include the accounts of the Company and its wholly-owned subsidiaries.
On August 27, 2021, the Company’s Board of Directors, in conjunction with the majority of the common stockholders, approved a one for four reverse stock split such that every holder of the Company’s common stock shall receive one share of Common Stock for every four shares owned. In addition, the Board authorized the Company to issue ten million shares of $0.001 par value Preferred Stock. The reverse stock split was made effective on March 7, 2022, simultaneous with the Company’s listing to the NYSE American. All shares amounts have retrospectively been stated at post-reverse split amounts and pricing.
Note 2 – Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts and balances of the Company and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). All intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
Estimated quantities of crude oil, natural gas and natural gas liquids (“NGL”) reserves are the most significant of the Company’s estimates. All reserve data used in the preparation of the Consolidated Financial Statements, as well as included in Supplemental Information of Oil and Natural Gas Producing Activities (Unaudited), are based on estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and NGL. There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and NGL reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil, natural gas and NGLs that are ultimately recovered.
Other items subject to estimates and assumptions include, but are not limited to, the carrying amounts of property, plant and equipment, asset retirement obligations, valuation allowances for deferred income tax assets, and valuation of derivative instruments. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions.
Although management believes these estimates are reasonable, actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting.
| -43- |
Out of Period Adjustments and Reclassifications
In
the third quarter of 2022, the Company identified and recorded an out-of-period adjustment related to the Joint Development Agreement
discussed in Note 5. The impact of recording this adjustment reduced Utility and Other Deposits and increased Lease Operating Expense
by approximately $
Gas and NGL sales in 2021 reflect an immaterial
reclassification of approximately $
Accounts Receivable
Accounts receivable include estimated amounts due from crude oil, natural gas, and NGL purchasers and from non-operating working interest owners. Accrued revenue related to product sales from purchasers and operators are due under normal trade terms, generally requiring payment within 60 days of production. For receivables from joint interest owners, the Company generally has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. The Company did not have an allowance for doubtful accounts at either December 31, 2022 or 2021. The Company’s accounts receivable as of December 31, 2022 and 2021 are as follows:
| 2022 | 2021 | |||||||
| Oil and Gas Receivables | $ | $ | ||||||
| Joint Interest Billings | ||||||||
| Receivable from Former CEO (See Note 18) | ||||||||
| Other | ||||||||
| Total Accounts Receivable | $ | $ | ||||||
Derivative Instruments
The Company enters into hedge agreements to manage its exposure to oil and natural gas price fluctuations. The fair value of derivative contracts is recognized as an asset or liability on the Company’s consolidated balance sheets. Realized gain or loss is recognized as a component of revenue when the derivative contracts mature. For contracts which have not matured, an unrealized gain or loss is recorded based on the change in the fair value of the outstanding contracts.
Inventory
Inventory consists of oil in tanks which has not been delivered and is valued at the lower of cost or net realizable value.
Oil and Natural Gas and Other Properties
The Company uses the successful efforts method of accounting for its oil and gas activities. Costs incurred are deferred until exploration and completion results are evaluated. At such time, costs of activities with economically recoverable reserves are capitalized as proven properties, and costs of unsuccessful or uneconomical activities are expensed.
Capitalized drilling costs are reviewed periodically for impairment. Costs related to impaired prospects or unsuccessful exploratory drilling is charged to expense. Management's assessment of the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such leaseholds impact the amount and timing of impairment provisions. An impairment expense could result if oil and gas prices decline in the future as it may not be economical to develop some of these unproved properties.
Lease options are capitalized as unproved property acquisition costs and are reviewed for impairment if indicators exist that the carrying value of the lease option may not be recoverable. If the lease options become impaired, expire or are abandoned, the options will be expensed. If proved reserves are discovered after the options are exercised, these costs will be reclassified as proved property.
Depreciation, depletion and amortization of producing properties is computed on the units-of-production method on a property-by-property basis. The units-of-production method is based primarily on estimates of proved reserve quantities. Due to uncertainties inherent in this estimation process, it is at least reasonably possible that reserve quantities will be revised in the near term. Changes in estimated reserve quantities are applied to depreciation, depletion and amortization computations prospectively.
Other property and equipment is depreciated on the straight-line method.
| -44- |
Segment Reporting
Operating segments are components of an enterprise that engage in activities from which it may earn revenues and incur expenses and for which separate operational financial information is available and is regularly evaluated by management. Based on the Company’s organization and management, it has only one reportable operating segment, which is oil and natural gas exploration and production.
Asset Retirement Obligations
The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related oil and natural gas property asset. Subsequently, the asset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability due to passage of time are recognized as an increase in the carrying amount of the liability through accretion expense. Based on certain factors, including commodity prices and costs, the Company may revise its previous estimates of the liability, which would also increase or decrease the related oil and natural gas property asset.
Revenue Recognition
The Company’s revenues are comprised solely of revenues from customers and include the sale of oil, natural gas and NGL. The Company believes that the disaggregation of revenue into these three major product types, as presented in the Consolidated Statements of Operations, appropriately depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors based on its single geographic region, the continental United States. Revenues are recognized at a point in time when production is sold to a purchaser at a determinable price, delivery has occurred, control has transferred and it is probable substantially all of the consideration will be collected. The Company fulfills its performance obligations under its customer contracts through delivery of oil, natural gas and NGL and revenues are recorded on a monthly basis. The Company receives payment from one to three months after delivery. Generally, each unit of product represents a separate performance obligation. The prices received for oil, natural gas and NGL sales under the Company’s contracts are generally derived from stated market prices which are then adjusted to reflect deductions including transportation, fractionation and processing. As a result, revenues from the sale of oil, natural gas and NGL will decrease if market prices decline. The sales of oil, natural gas and NGL, as presented on the Consolidated Statements of Operations, represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling oil, natural gas and NGL on behalf of royalty or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. Variances between the Company’s estimated revenue and actual payment are recorded in the month the payment is received. Historically, these differences have been insignificant.
At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are recorded in Accounts Receivable in the Consolidated Balance Sheets. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from such revenues in the Consolidated Statements of Operations.
Oil Sales
Oil production is transported from the wellhead to tank batteries or delivery points through flow-lines or gathering systems. Purchasers of the oil take delivery at the tank batteries and transport the oil by truck or at a pipeline delivery point and the Company collects a market price, net of pricing differentials. Revenue is recognized when control transfers to the purchaser at the net price received by the Company.
Natural Gas and NGL Sales
Under the Company’s natural gas sales arrangements, the purchaser takes control of wet gas at a delivery point near the wellhead or at the inlet of the purchaser’s processing facility. The purchaser gathers and processes the wet gas and remits proceeds to the Company for the resulting natural gas and NGL sales. Based on the nature of these arrangements, the processor is the agent and the purchaser is the Company’s customer, thus, the Company recognizes natural gas and NGL sales based on the net amount of proceeds received from the purchaser.
Transaction Price Allocated to Remaining Performance Obligations
Substantially all of the Company’s product sales are short-term in nature with a contract term of one year or less. For these contracts, the Company has utilized the practical expedient in ASC 606 which exempts the Company from the requirements to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
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For the Company’s product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC 606 which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.
Prior-Period Performance Obligations
The Company records revenue in the month that product is delivered to the purchaser. Settlement statements for certain natural gas and NGL sales, however, may not be received for 30 to 90 days after the date the product is delivered, and as a result the Company is required to estimate the amount of product delivered to the purchaser and the price that will be received for the sale of the product. In these situations, the Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between the Company’s revenue estimates and actual revenue received have historically been insignificant. For the years ended December 31, 2022 and 2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
Stock-Based Compensation
The Company recognized stock-based compensation expense associated with granted stock options. The Company accounts for forfeitures of equity-based incentive awards as they occur. Stock-based compensation expense related to time-based restricted stock units is based on the price of the common stock on the grant date and recognized as vesting occurs.
Income Taxes
The Company accounts for income taxes in accordance with the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to the taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is established if management determines it is more likely than not that some portion of a deferred tax asset will not be realized.
The Company calculates and discloses basic earnings per share ("Basic EPS") and diluted earnings per share ("Diluted EPS"). The computation of basic earnings per share is computed by dividing earnings available to common stockholders by the weighted average number of outstanding common shares during the period.
Diluted EPS gives effect to all dilutive potential common shares outstanding during the period. The computation of Diluted EPS does not assume conversion, exercise or contingent exercise of securities that would have an anti-dilutive effect on losses. As a result, if there is a loss from continuing operations, Diluted EPS is computed in the same manner as Basic EPS.
Fair Value Measurements
The Financial Accounting Standards Board ("FASB") fair value measurement standards define fair value, establish a consistent framework for measuring fair value and establish a fair value hierarchy based on the observability of inputs used to measure fair value.
The three-level fair value hierarchy for disclosure of fair value measurements defined by ASC Topic 820 is as follows:
Level 1 – Unadjusted, quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is defined as a market where transactions for the financial instrument occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Inputs, other than quoted prices within Level 1, that are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.
Level 3 – Prices or valuations that require unobservable inputs that are both significant to the fair value measurement and unobservable. Valuation under Level 3 generally involves a significant degree of judgment from management.
A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instrument’s complexity. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level. There were no transfers between fair value hierarchy levels for the years ended December 31, 2022 and 2021.
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Impairment of oil and natural gas properties - The fair value of proved and unproved oil and natural gas properties was measured using valuation techniques that convert the future cash flows to a single discounted amount. Significant inputs to the valuation of proved and unproved oil and natural gas properties include estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average costs of capital. The Company utilized a combination of the New York Mercantile Exchange ("NYMEX") strip pricing and consensus pricing to value the reserves, then applied various discount rates depending on the classification of reserves and other risk characteristics. For significant acquisitions, management utilized the assistance of a third-party valuation expert to estimate the value of the oil and natural gas properties acquired.
The fair value of asset retirement obligations is included in proved oil and natural gas properties with a corresponding liability. The fair value was determined based on a discounted cash flow model, which included assumptions of the estimated current abandonment costs, discount rate, inflation rate and timing associated with the incurrence of these costs.
The inputs used to value oil and natural gas properties for impairments and asset retirement obligations require significant judgment and estimates made by management and represent Level 3 inputs.
Financial instruments and other- The fair values determined for accounts receivable, accrued expenses and other current liabilities were equivalent to the carrying value due to their short-term nature.
Derivatives – Derivative financial instruments are carried at fair value and measured on a recurring basis. The Company’s commodity price hedges are valued based on discounted future cash flow models that are primarily based on published forward commodity price curves; thus, these inputs are designated as Level 2 within the valuation hierarchy.
The fair values of derivative instruments in asset positions include measures of counterparty nonperformance risk, and the fair values of derivative instruments in liability positions include measures of the Company’s nonperformance risk. These measurements were not material to the Consolidated Financial Statements.
Related Party Transactions
Transactions between related parties are considered to be related party transactions even though they may not be given accounting recognition. FASB ASC 850, Related Party Disclosures (“FASB ASC 850”) requires that transactions with related parties that would have influence in decision making shall be disclosed so that users of the financial statements can evaluate their significance. Related party transactions typically occur within the context of the following relationships: affiliates of the entity; entities for which investments in their equity securities is typically accounted for under the equity method by the investing entity; trusts for the benefit of employees; principal owners of the entity and members of their immediate families; management of the entity and members of their immediate families; and other parties that can significantly influence the management or operating policies of the transacting parties and can significantly influence the other to an extent that one or more of the transacting parties might be prevented from fully pursuing its own separate interests.
Recently Issued Accounting Pronouncements
FASB periodically issues new accounting standards in a continuing effort to improve standards of financial accounting and reporting. The Company has reviewed the recently issued pronouncements and concluded that the following new accounting standards are applicable:
In August 2020, the FASB issued ASU 2020-06, Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The amendments in this ASU affect entities that issue convertible instruments and/or contracts in an entity’s own equity. The amendments in this ASU primarily affect convertible instruments issued with beneficial conversion features or cash conversion features because the accounting models for those specific features are removed. However, all entities that issue convertible instruments are affected by the amendments to the disclosure requirements of this ASU. For contracts in an entity’s own equity, the contracts primarily affected are freestanding instruments and embedded features that are accounted for as derivatives under the current guidance because of failure to meet the settlement conditions of the derivatives scope exception related to certain requirements of the settlement assessment. Also affected is the assessment of whether an embedded conversion feature in a convertible instrument qualifies for the derivatives scope exception. Additionally, the amendments in this ASU affect the diluted EPS calculation for instruments that may be settled in cash or shares and for convertible instruments. The amendments in this ASU are effective for public business entities, excluding entities eligible to be smaller reporting companies, for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. For all other entities, the amendments are effective for fiscal years beginning after December 15, 2023, including interim periods within those fiscal years. The Board specified that an entity should adopt the guidance as of the beginning of its annual fiscal year. The Board decided to allow entities to adopt the guidance through either a modified retrospective method of transition or a fully retrospective method of transition. The Company is analyzing the effect that adoption will have but does not expect a material impact as a result of adopting these standards.
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In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses. This ASU, as further amended, affects trade receivables, financial assets and certain other instruments that are not measured through net income. This ASU will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost and is effective for financial statements issued for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years. The Company does not believe the adoption of this ASU will have a material impact on the Company's consolidated financial statements since the Company does not have a history of material credit losses.
Note 3 – Property
The capitalized costs of oil and natural gas properties as of December 31, 2022 and 2021 are as follows:
| 2022 | 2021 | |||||||
| Proved Properties | $ | $ | ||||||
| Unproved Properties | ||||||||
| Work in process | | |||||||
| Gross capitalized costs | ||||||||
| Depreciation, Depletion, Amortization and Impairment | ( | ) | ( | ) | ||||
| Total Oil and Gas Properties, Net | $ | $ | ||||||
The Company assesses its oil and gas properties for impairment when circumstances indicate the carrying value may be greater than its estimated future net cash flows. In 2022, estimated future cash flows from the Company’s properties in Louisiana were less than the net book value. As a result, the Company recorded a $936,000 impairment expense in 2022.
In
April 2022, the Company purchased working interests of oil and natural gas properties primarily located in the Landa field in North Dakota
and assumed the role of operator. The Company paid approximately $
Other property and equipment consists of operating lease assets, vehicles, office furniture, and equipment with lives ranging from three to five years. The capitalized costs of other property and equipment as of December 31, 2022 and 2021 are as follows:
| 2022 | 2021 | |||||||
| Other property and equipment, at cost | $ | $ | ||||||
| Less: accumulated depreciation | ( | ) | ( | ) | ||||
| Oher property and equipment, net | $ | $ | ||||||
Note 4 – Acquisition of XTO Properties
On March 12, 2021 the Company, through its wholly owned subsidiary Empire New Mexico, entered into a purchase and sale agreement with XTO Holdings, LLC (a subsidiary of ExxonMobil) (the “Seller’) to acquire, among other things, certain oil and natural gas properties in New Mexico. The purchase price was $ subject to customary adjustments. The transaction closed on May 14, 2021 with an effective date of January 1, 2021.
The XTO acquisition has been assessed under the screen test for business combinations under FASB ASC 805, Business Combinations (“ASC 805”). The XTO acquisition met the screen test and has been accounted for as an asset acquisition using the acquisition method of accounting. Under the accounting for asset acquisitions, the acquisition is recorded using a cost accumulation and allocation model under which the cost of the acquisition is allocated on a relative fair value basis to the assets acquired and liabilities assumed. Acquisition-related transaction costs are capitalized as a component of the cost of the assets acquired.
As
a condition of the sale, the Company purchased a $
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The following table sets forth the Company's purchase price allocation:
| Fair Value of Assets Acquired | ||||
| Oil and natural gas properties | $ | |||
| Inventory of oil in tanks | ||||
| Vehicles | ||||
| Asset retirement obligations | ||||
| Total assets acquired | ||||
| Fair Value of Liabilities Assumed | ||||
| Royalty suspense | ||||
| Asset retirement obligations | ||||
| Total liabilities assumed | ||||
| Purchase Price | ||||
The value of oil and gas properties was based on an allocation of the purchase price which included assignment of values to the other identifiable assets acquired and liabilities assumed. The value of inventory, vehicles, and royalty suspense was based on their relative fair values as described above.
The fair value of asset retirement obligations is included in proved oil and natural gas properties with a corresponding liability in the table above. The fair value was determined based on a discounted cash flow model, which included assumptions of the estimated current abandonment costs, discount rate, inflation rate and timing associated with the incurrence of these costs.
On October 7, 2022, the Company entered into a final settlement agreement with XTO. The provisions of this settlement allowed the Company to substitute the performance bond and letter of credit that were put into place with the transaction for a new performance bond that does not require the Company to have collateral invested in the performance bond. Due to the nature and timing of the settlement, the result of the final settlement was a non-cash expense of approximately $1.4 million to Other Income (Expense) on the Consolidated Statements of Operations in 2022.
Note 5 – Joint Development Agreement
On
August 6, 2020 the Company, through its wholly owned subsidiary, Empire Texas, entered into a joint development agreement (the “JDA”)
with Petroleum & Independent Exploration, LLC and related entities (“PIE”), a related party (See Note 12), dated August
1, 2020. Under the terms of the JDA, PIE will perform recompletion or workover on specified mutually agreed upon wells (“Workover
Wells”) owned by Empire Texas. To fund the work, PIE entered into a term loan agreement with Empire Texas dated August 1, 2020,
whereby PIE will loan up to $
In
addition,
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Note 6 - Asset Retirement Obligations
The Company’s asset retirement obligations represent the estimated present value of the estimated cash flows the Company will incur to plug, abandon and remediate its producing properties at the end of their productive lives, in accordance with applicable state laws. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company’s credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations.
The Company’s asset retirement obligation transactions during the years ended December 31, 2022 and 2021 are summarized in the table below.
| For the Year Ended December 31, | ||||||||
| 2022 | 2021 | |||||||
| Asset retirement obligations, beginning of period | $ | $ | ||||||
| Liabilities assumed in acquisitions | ||||||||
| Revisions | ( | ) | ||||||
| Liabilities settled | ( | ) | ||||||
| Accretion expense | ||||||||
| Asset retirement obligation, end of period | $ | $ | ||||||
The revisions in 2022 primarily relate to the identification of nonproducing wells, including injection wells and temporarily abandoned wells in New Mexico.
Note 7 – Commodity Derivative Financial Instruments
The Company uses derivative financial instruments to manage its exposure to commodity price fluctuations. Commodity derivative instruments are used to reduce the effect of volatility of price changes on the oil and natural gas the Company produces and sells. The Company does not enter into derivative financial instruments for speculative or trading purposes. The Company’s derivative financial instruments consist of put options.
The Company does not designate its derivative instruments to qualify for hedge accounting. Accordingly, the Company reflects changes in the fair value of its derivative instruments in its consolidated statements of operations as they occur. Unrealized gains and losses related to the contracts are recognized and recorded as an asset or liability on the Company’s consolidated balance sheets.
The following table summarizes the net realized and unrealized amounts reported in earnings related to the commodity derivative instruments for the years ended December 31, 2022 and 2021:
| For the Year Ended December 31, | ||||||||
| 2022 | 2021 | |||||||
| Gain (loss) on derivatives: | ||||||||
| Oil derivatives | $ | ( | ) | $ | ( | ) | ||
The following represents the Company’s net cash receipts from (payments on) derivatives for the years ended December, 2022 and 2021:
| For the Year Ended December 31, | ||||||||
| 2022 | 2021 | |||||||
| Oil derivatives | $ | ( | ) | $ | ( | ) | ||
| Natural gas derivatives | ( | ) | ||||||
| Total | $ | ( | ) | $ | ( | ) | ||
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The following table sets forth the Company’s outstanding derivative contracts at December 31, 2022:
| 1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | ||||
| 2023 | |||||||
| WTI Index Put Options: | |||||||
| Quarterly volume (Bbl) | |
|
|
| |||
| Floor Price (Bbl) | $ |
$ |
$ |
$ |
Note 8 – Debt and Long Term Note Payable - Related Party
The following table represents the Company’s outstanding debt.
| As of December 31, | ||||||||
| 2022 | 2021 | |||||||
| Senior Revolver Loan Agreement | $ | $ | ||||||
| Long Term Note Payable – Related Party | ||||||||
| Equipment and vehicle notes, | ||||||||
| Note Payable to Insurance Provider, bears | ||||||||
| Total Debt | ||||||||
| Less: Current Maturities | ( | ) | ( | ) | ||||
| Less: Long Term Note Payable – Related Party | ( | ) | ( | ) | ||||
| Long-Term Debt | $ | $ | ||||||
On
July 7, 2021 the Company entered into the Fourth Amendment to its Senior Revolver Loan Agreement with CrossFirst Bank (“CrossFirst”)
as further amended by Letter Agreements in conjunction with redetermination dates (“the Amended Agreement”). The maximum
amount that can be advanced under the Agreement is $20,000,000 and the existing commitment amount following a
On
May 5, 2020, the Company received an SBA Payroll Protection Plan (“PPP”) loan for $
On
April 30, 2021, the Company received a Second Draw SBA PPP loan for $
Long Term Note Payable - Related Party
In
August 2020, concurrent with the Joint Development Agreement with Petroleum and Independent Exploration, LLC (“PIE”), a related
party, the Company entered into a term loan agreement dated August 1, 2020, whereby PIE will loan up to $
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Note 9 – Convertible Notes Payable
Senior Secured Note Agreement
On
May 14, 2021, the Company’s wholly owned subsidiary, Empire New Mexico entered into a Senior Secured Convertible Note Agreement
(the “Secured Note”) in the amount of $
As
partial consideration for the issuance of the Secured Note, Energy Evolution received a closing fee of shares of the Company’s
common stock and warrants to purchase
On
September 29, 2021 the parties entered into a Loan Modification Agreement (the “Amended Secured Note”) pursuant to which
Energy Evolution exchanged $
Pursuant
to the Amended Secured Note, the Company’s obligations with respect to a registration statement under the Secured Note were extended,
the Company executed and delivered a Pledge and Security Agreement granting Energy Evolution a first priority perfected security interest
in the Company’s membership interest in Empire New Mexico, d/b/a Green Tree New Mexico, the Company and Green Tree New Mexico agreed
to use commercial reasonable best efforts to separate Green Tree New Mexico from the Company as an independent business on or before
December 31, 2022 in a spin-off to stockholders of the Company. In accordance with ASC 470-20, the Company accounted for this exchange
as an induced conversion based on the short period time of the offer was open and the substantive conversion feature offer. The Company
accounted for the conversion of the debt instruments as an inducement by expensing the fair value of the instruments that were issued
in excess of the original terms of the Secured Notes. The Company reduced the outstanding debt by $
On
December 30, 2021, the Company amended the Amended Secured Note to allow full conversion of the remaining principal and accrued interest
at that date. $
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Unsecured Convertible Notes
In
May 2021 the Empire New Mexico entered into $
The
Company determined the embedded conversion features of the Unsecured Notes were equity-classified financing instruments. The fair value
of the conversion feature was determined using a beneficial conversion model based on a 60-day weighted average stock price and the maximum
number of shares to be received if converted. As issuance, the amount recorded to additional paid in capital was $
As
an inducement for investors to enter into the Unsecured Convertible Notes, the Company’s Chief Executive Officer and President
collectively offered to each investor the right to purchase a number of shares of common stock equal to
Note 10 - Leases
As a lessee, the Company leases its corporate office headquarters in Tulsa, Oklahoma and three field offices. The leases expire between 2024 and 2027. The corporate office has an option to renew for an additional five-year term. The option to renew the lease is generally not considered reasonably certain to be exercised. Therefore, the period covered by such optional period is not included in the determination of the term of the lease and the lease payments during these periods are similarly excluded from the calculation of right-of-use lease asset and lease liability balances.
The Company recognizes right-of use lease expense on a straight-line basis, except for certain variable expenses that are recognized when the variability is resolved, typically during the period in which they are paid. Variable right-of-use lease payments typically include charges for property taxes, insurance, and variable payments related to non-lease components, including common area maintenance.
Right
of use lease expense was approximately $
Supplemental balance sheet information related to the right of use leases is as follows:
| As of December 31, | ||||||||
| 2022 | 2021 | |||||||
| Operating lease asset (included in Other Property and Equipment) | $ | $ | ||||||
| Current portion of lease liability | $ | $ | ||||||
| Long-term lease liability | ||||||||
| Total right of use lease liabilities | $ | $ | ||||||
The weighted average remaining term for the Company’s right of use leases is years.
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| 2023 | $ | |||||
| 2024 | ||||||
| 2025 | ||||||
| 2026 | ||||||
| 2027 | ||||||
| Thereafter | ||||||
| Total lease payments | ||||||
| Less imputed interest | ( | ) | ||||
| Total lease obligation | $ |
Note 11 – Equity
Pursuant to the Company’s Amended and Restated Certificate of Incorporation (“Charter”), effective as of March 4, 2022, the total number of shares of all classes of stock that the Company has the authority to issue is 200,000,000, consisting of shares of common stock, par value $ per share, and shares of preferred stock, par value $ per share.
Preferred Stock
Preferred stock may be issued from time to time in one or more series at the direction of the Board of Directors and the directors also have the ability to fix dividend rates and rights, liquidation preferences, voting rights, conversion rights, rights and terms of redemption and other rights, preferences, privileges and restrictions as determined by the Board of Directors, subject to certain limitations set forth in the Charter.
Series A Voting Preferred Stock
On March 8, 2022, the Company formalized the issuance of preferred stock as was required under the terms of the Company's May 2021 financing agreements with Energy Evolution (Master Fund), Ltd. (the “Fund”) and issued six shares of Series A Voting Preferred Stock. The Series A Voting Preferred Stock was issued in connection with the strategic investment in the Company by the Fund. For so long as the Series A Voting Preferred Stock is outstanding, the Company’s Board of Directors will consist of six directors. Three of the directors are designated as the Series A Directors and the three other directors (each, a “common director”) are elected by the holders of common stock and/or any preferred stock (other than the Series A Voting Preferred Stock) granted the right to vote on the common directors. Any Series A Director may be removed with or without cause but only by the affirmative vote of the holders of a majority of the Series A Voting Preferred Stock voting separately and as a single class. The holders of the Series A Voting Preferred Stock have the exclusive right, voting separately and as a single class, to vote on the election, removal and/or replacement of the Series A Directors. Holders of common stock or other preferred stock do not have the right to vote on the Series A Directors. The approval of the holders of the Series A Voting Preferred Stock, voting separately and as a single class, is required to authorize any resolution or other action to issue or modify the number, voting rights or any other rights, privileges, benefits, or characteristics of the Series A Voting Preferred Stock, including without limitation, any action to modify the number, structure and/or composition of the Company’s current Board of Directors.
The
Series A Voting Preferred Stock is held by Phil Mulacek, chairman of the Board of Directors and one of the principals of the Fund, as
the Fund’s designee (the “Initial Holder”). The Series A Voting Preferred Stock may be transferred only to certain
controlled affiliates of the Initial Holder (“Permitted Transferees”), and
The Series A Voting Preferred Stock is not entitled to receive any dividends or distributions of cash or other property except in the event of any liquidation, dissolution or winding up of the Company’s affairs. In such event, before any amount is paid to the holders of the Company’s common stock but after any amount is paid to the holders of the Company’s senior securities, the holders of the Series A Voting Preferred Stock will be entitled to receive an amount per share equal to $1.00.
Except as discussed above or as otherwise set forth in the certificate of designation of the Series A Voting Preferred Stock, the holders of the Series A Voting Preferred Stock have no voting rights.
The
Series A Voting Preferred Stock is not redeemable at the Company’s election or the election of any holder, except the Company may
elect to redeem the
| • | any or all shares of Series A Voting Preferred Stock are held by anyone other than the Initial Holder or a Permitted Transferee; or |
| • | the Series A Holders together hold less than shares of the Company’s outstanding common stock. |
The Series A Voting Preferred Stock is not convertible into common stock or any other security.
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Common Stock
On August 27, 2021 the Company’s Board of Directors approved a one-for-four reverse stock split such that every holder of the Company’s common stock would receive one share of common stock for every four shares owned. The reverse stock split was effective as of 6:00 p.m. Eastern Time on March 7, 2022, immediately prior to the Company’s listing of its common stock on the NYSE American. All share amounts have retrospectively been stated at post-reverse split amounts and pricing.
The holders of shares of common stock are entitled to one vote per share for all matters on which common stockholders are authorized to vote on. Examples of matters that common stockholders are entitled to vote on include, but are not limited to, election of three of the six directors and other common voting situations afforded to common stockholders.
On
August 7, 2020 concurrently with the Joint Development Agreement with Petroleum & Independent Exploration, LLC and related entities
(“PIE”), the companies entered into a Securities Purchase Agreement (“Securities Agreement”) whereby
During
February and March 2021, the Company issued to a group of accredited investors shares of its common stock and warrants to purchase
shares of its common stock for $ per share which expires on
In September and October 2022, a former director of the Company exercised warrants granted in November 2017 to purchase shares of common stock for $ per share.
In
connection with the purchase of XTO assets the Company issued a Senior Secured Convertible Note due
Additionally,
in conjunction with the purchase of XTO assets, the Company entered into $
On April 3, 2019, the Board of Directors of the Company adopted the Empire Petroleum Corporation 2019 Stock Option Plan (the “2019 Stock Option Plan”). The total number of shares of common stock that may be issued pursuant to stock options under the 2019 Stock Option Plan was . Further, on April 3, 2019 the Company granted Mr. Pritchard and Mr. Morrisett each, options to purchase shares of common stock of the Company at an exercise price of $ per share. The options vested in three installments with
| -55- |
vesting immediately and vesting each in April 2020 and April 2021. All of the options expire in April 2029. The value allocated to the vested options was the fair value determined using the Black-Scholes option valuation with the following assumptions: no dividend yield, expected annual volatility of 213%, risk free interest rate of % and an expected useful life of years. The fair value of the vested options of $ was recorded as compensation expense and allocated to Paid in Capital in 2019. In 2021 and 2020, the fair value of the options which vested in April of the respective year of $ was recorded as compensation expense and allocated to Additional Paid in Capital. All of the options were vested as of December 31, 2021. As a result of the adoption of a 2021 plan, the Board of Directors and management have determined that there would be no further issuances from the 2019 Stock Option Plan. In April 2022, Mr. Pritchard exercised options to purchase 235,000 shares of common stock. As of December 31, 2022, there were 1,943,200 unexercised options under the Stock Option Plan.
On
August 27, 2021, the Board of Directors of the Company adopted the Company’s 2021 Stock and Incentive Compensation Plan (the “2021
Incentive Plan”) which was subsequently approved by stockholders of the Company. The total number of shares of common stock that
could be issued pursuant to the 2021 Incentive Plan is . Four
grants were made in 2021 that amounted to options. Two of the grants were for a cumulative amount of options and vested
immediately upon grant in November 2021. Valuation was calculated using the Black-Scholes option valuation model with the following assumptions:
no dividend yield, expected annual volatility of
On
February 28, 2022, the Board of Directors of the Company granted a combination of stock options and restricted stock units under the
2021 Incentive Plan. Stock options totaling shares were granted to employees and members of management with
-year
vesting terms and expirations of
On August 26, 2022, the stockholders of the Company approved the Company’s 2022 Stock and Incentive Compensation Plan (the “2022 Incentive Plan”) which reserves shares of the Company’s common stock for issuance thereunder. As a result of such approval, no further awards will be made under the 2021 Incentive Plan. The 2022 Stock and Incentive Plan authorizes the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and other stock-based awards (restricted stock awards, restricted stock units, performance shares and performance units are collectively referred to as restricted stock units for purposes of this footnote. At December 31, 2022, shares of our common stock were available for future grants.
Restricted Stock Units
Each RSU represents the contingent right to receive one share of common stock. The holders of outstanding RSUs do not receive dividends or have voting rights prior to vesting and settlement. The Company determines the fair value of granted RSUs based on the market price of the common stock on the date of the grant. Compensation expense for granted RSUs is recognized on a straight-line basis over the vesting and is net of forfeitures, as incurred. Stock-based compensation is included in General and Administrative expense in the Consolidated Statements of Operations and is recorded with a corresponding increase in Additional Paid-in Capital within the Consolidated Balance Sheets.
The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2022.
| Weighted Average | ||||||||||
| Shares | Fair Value (a) | |||||||||
| Outstanding, December 31, 2021 | $ | |||||||||
| Granted | ||||||||||
| Vested | ||||||||||
| Outstanding, December 31, 2022 | $ | |||||||||
| (a) |
| -56- |
| 2022 | ||||
| Weighted Average grant date fair value of restricted stock units granted during the year, per share | $ | |||
| Total fair value of restricted stock units vested during the year | $ | |||
Stock Options
| Weighted Average | ||||||||||
| Options | Exercise Price | |||||||||
| Outstanding, December 31, 2020 | $ | |||||||||
| Granted | ||||||||||
| Expired | ( | ) | ||||||||
| Outstanding, December 31, 2021 | $ | |||||||||
| Granted | ||||||||||
| Exercised | ( | ) | ||||||||
| Outstanding, December 31, 2022 | $ | |||||||||
The following table summarizes information about stock options outstanding as of December 31, 2022:
| Range of | Options | Weighted Average | Weighted | Options | Weighted |
| Exercise | Outstanding | Remaining | Average | Exercisable | Average |
| Prices | at 12/31/22 | Contractual Life | Exercise Price | at 12/31/22 | Exercise Price |
| $ to $ | $ |
$ |
Note 13 – Income Taxes
The current and deferred income tax provision for the years ended December 31, 2022 and 2021 were comprised for the following:
| 2022 | 2021 | |||||||
| Current | $ | $ | ||||||
| Deferred | ||||||||
| Income tax provision (benefit) | $ | $ | ||||||
At
December 31, 2022, the Company had net operating loss carryforwards of approximately $
| -57- |
Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax basis of assets and liabilities. The Company’s net tax position as of December 31, 2022 and 2021 is as follows:
| 2022 | 2021 | |||||||
| Deferred tax assets: | ||||||||
| Loss carry-forwards | $ | $ | ||||||
| Oil and gas Properties | ||||||||
| Right of use assets | ||||||||
| Stock option grants | ||||||||
| Asset retirement obligation | ||||||||
| Derivatives | ||||||||
| Other | ||||||||
| Total deferred tax assets | ||||||||
| Deferred tax liabilities: | ||||||||
| Oil and gas Properties | ( | ) | ||||||
| Other property and equipment | ( | ) | ( | ) | ||||
| Derivatives | ( | ) | ||||||
| Other | ( | ) | ||||||
| Total deferred tax liabilities | ( | ) | ( | ) | ||||
| Net deferred tax asset (liability) before valuation allowance | ||||||||
| Valuation allowance | ( | ) | ( | ) | ||||
| Net deferred taxes | $ | $ | ||||||
Reconciliations of the tax provision computed at the statutory federal rate to the Company’s total income tax benefit for the years ended December 31, 2022 and 2021 are as follows:
| 2022 | 2021 | ||||||
| $ | % | $ | % | ||||
| Provision (benefit) at statutory rate | |
( |
|||||
| State taxes (net of federal impact) | |
( |
|||||
| Nondeductible expenses | |
|
- | ||||
| Return to Accrual | ( |
- |
— | ||||
| Valuation Allowance | |
|
- | ||||
| Income tax provision | |
||||||
Utilization
of the Company’s loss carryforwards is dependent on realizing taxable income. The Company recorded valuation allowances of
$
The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would likely than not would be sustained by examination. Therefore, at December 31, 2022, the Company has not established any reserves for, nor recorded any unrecognized benefits related to uncertain tax positions.
Diluted Earnings per Share (“EPS”) gives effect to all dilutive potential common shares outstanding during the period. The computation of Diluted EPS does not assume conversion, exercise or contingent exercise of securities that would have an anti-dilutive effect on losses. As a result, if there is a loss from continuing operations, Diluted EPS is computed in the same manner as Basic EPS. At December 31, 2021, the Company had options outstanding that were not included in the calculation of earnings per share for the periods then ended.
| -58- |
Note 15 – Related Party Transactions
The
Energy Evolution Master Fund, Ltd. (“Energy Evolution”) is a related party of the Company as it beneficially owns approximately
In
March 2021, the majority owner of PIE, through the exercise of warrants, became a significant shareholder of the Company’s outstanding
shares of stock (See Note 11). The Company has a joint development agreement with PIE to perform recompletion or workover on specified
mutually agreed upon wells (See Note 5). As of December 31, 2022, the Company has incurred obligations of approximately $
Note 16 – Commitments and Contingencies
From time to time, the Company is subject to various legal proceedings arising in the ordinary course of business, including proceedings for which the Company may not have insurance coverage. While many of these matters involve inherent uncertainty, as of the date hereof, the Company does not currently believe that any such legal proceedings will have a material adverse effect on the Company’s business, financial position, results of operations or liquidity.
The Company is subject to extensive federal, state, and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Management believes no materially significant liabilities of this nature existed as of the balance sheet date.
The
Company was subject to a sales tax audit related to its Texas entity and received the initial assessment notice in April 2022. The Company
has accrued $
Note 17 – Concentrations
The Company’s producing properties and oil and natural gas reserves are all located in Louisiana, New Mexico, North Dakota, Montana, and Texas. Because of the concentration, the Company is exposed to the impact of regional supply and demand factors, processing or transportation capacity constraints, severe weather events, water shortages, and government regulations specific to the geographic area.
For
the year ended December 31, 2022, the Company sold
The Company’s cash balances may at times exceed FDIC insurance limits. The Company maintains cash accounts at reputable financial institutions.
Note 18 – Subsequent Events
On
March 16, 2023, Thomas W. Pritchard resigned as Chief Executive Officer and a director of the Company to pursue other opportunities.
Although not required under Mr. Pritchard’s Employment Agreement with the Company, in recognition of Mr. Pritchard’s past
service to the Company, the Company will pay Mr. Pritchard severance benefits in the amount of approximately $
On March 17, 2023, the Board of Directors appointed Michael R. Morrisett to the position of Chief Executive Officer, in addition to his current duties of President and Principal Financial Officer of the Company. Mr. Morrisett is not receiving any additional compensation for assuming the role of Chief Executive Officer.
| -59- |
EMPIRE PETROLEUM CORPORATION
Supplemental Information of Oil and Natural Gas Producing Activities (Unaudited)
December 31, 2022 and 2021
The following reserve estimates present the Company's estimate of the proven natural gas and oil reserves and net cash flow of the Company’s properties, in accordance with the guidelines established by the Securities and Exchange Commission. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing natural gas and oil properties. Accordingly, the estimates are expected to change as future information becomes available. All the oil and natural gas reserves are located in Louisiana, New Mexico, North Dakota, Montana and Texas.
Costs Incurred Related to Oil and Gas Activities
Costs incurred includes capitalized costs of properties, equipment, and lease facilities for oil and natural gas producing activities.
| Years Ended December 31, | ||||||||
| 2022 | 2021 | |||||||
| Acquisition | $ | 2,702,613 | $ | 23,780,111 | ||||
| Exploration | — | — | ||||||
| Development | 11,206,207 | 1,970,410 | ||||||
| $ | 13,908,820 | $ | 25,750,521 | |||||
Reserve Quantity Information
Proved oil and natural gas reserves are those quantities of oil and gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditures is required for recompletion. The information below excludes proved undeveloped reserves. Below are the net quantities of net proved developed reserves of the Company’s properties:
| Oil (MMBbls) | Gas (MMcf) | NGLs (a) | MBOE | ||
| Balance, December 31, 2020 | 3,661 | 971 | 3,823 | ||
| Acquisition of Reserves | 5,634 | 10,533 | 7,390 | ||
| Revisions | (617) | 251 | (576) | ||
| Extensions | 150 | 51 | 159 | ||
| Divestiture of Reserves | (47) | 27 | (42) | ||
| Production | (333) | (625) | (437) | ||
| Balance, December 31, 2021 | 8,448 | 11,208 | 87 | 10,404 | |
| Acquisition of Reserves | 650 | 205 | 61 | 745 | |
| Revisions | (350) | 1,834 | 2,248 | 2,203 | |
| Extensions | 561 | 566 | 27 | 682 | |
| Production | (483) | (876) | (161) | (790) | |
| Balance, December 31, 2022 | 8,826 | 12,937 | 2,262 | 13,244 |
(a) The Company did not present NGLs separately in 2021.
The 2021 acquisitions primarily relate to the XTO acquisition. The 2022 acquisitions relate to small acquisition in our Rockies and New Mexico regions.
| -60- |
Standardized Measure of Discounted Future Net Cash Flows Relating to Oil and Natural Gas Reserves
The standardized measure of discounted future net cash flows relating to oil and natural gas reserves and associated changes in standard measure amounts were prepared in accordance with the provision of Financial Accounting Standard Board ASC 932-235-555. Future cash inflows were computed by applying average prices of oil and natural gas for the last 12 months to estimated future production. Future production and development costs were computed by estimating the expenditures to be incurred in developing the oil and natural gas reserves at the end of the year, based on yearend costs and assuming continuation of existing economic conditions. Future net cash flows are discounted at the rate of 10% annually to derive the standardized measure of discounted cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the acquired properties' oil and natural gas reserves. Standard measure amounts are:
| December 31, | ||||||||
| 2022 | 2021 | |||||||
| Future cash inflows | $ | 941,172,544 | $ | 627,654,125 | ||||
| Future production costs | (509,154,924 | ) | (362,254,813 | ) | ||||
| Future development costs | (55,901,780 | ) | (33,021,749 | ) | ||||
| Future income tax expense | (90,724,632 | ) | (30,614,383 | ) | ||||
| Future net cash flows | 285,391,208 | 201,763,180 | ||||||
| 10% annual discount for estimated timing of cash flows | (137,723,795 | ) | (107,911,087 | ) | ||||
| Standardized measure | $ | 147,667,413 | $ | 93,852,093 | ||||
The 12-month average prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the properties' reserves. The prices for the properties' reserves were as follows:
| 2022 | 2021 | |||||||
| Oil (BBl) | $ | 91.14 | $ | 64.31 | ||||
| Natural gas (MMBtu) | $ | 4.23 | $ | 7.34 | * | |||
*Pricing includes revenue received from NGL sales as well as natural gas.
Changes in the Standardized Measure of Discounted Future Net Cash Flows at 10% per annum are as follows:
| December 31, | ||||||||
| 2022 | 2021 | |||||||
| Beginning of year | $ | 93,852,093 | $ | 20,770,080 | ||||
| Net change in prices and production costs | 24,651,555 | 13,080,689 | ||||||
| Net change in future development costs | (7,141,431 | ) | 782,210 | |||||
| Oil & Gas net revenue | (21,418,327 | ) | (10,587,395 | ) | ||||
| Extensions | 11,037,719 | 5,026,479 | ||||||
| Acquisition of reserves | 12,043,912 | 90,104,017 | ||||||
| Divestiture of reserves | — | (318,813 | ) | |||||
| Revisions of previous quantity estimates | 46,871,217 | (3,794,860 | ) | |||||
| Net change in taxes | (32,133,473 | ) | (15,544,094 | ) | ||||
| Accretion of discount | 10,939,619 | 2,077,008 | ||||||
| Changes in timing and other | 8,964,529 | (7,743,228 | ) | |||||
| End of year | $ | 147,667,413 | $ | 93,852,093 | ||||
Estimates of economically recoverable natural gas and oil reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties, and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of natural gas and oil may differ materially from the amounts estimated.
-61-
EXHIBIT 21
EMPIRE PETROLEUM CORPORATION
Subsidiaries
| Entity | Place of Incorporation/Organization |
| Empire Louisiana LLC | Delaware |
| Empire ND Acquisition LLC | Delaware |
| Empire New Mexico LLC | Delaware |
| Empire North Dakota LLC | Delaware |
| Empire Northwest Shelf LLC | Delaware |
| Empire Texas LLC | Delaware |
| Empire Texas GP LLC | Texas |
| Empire Texas Operating LLC | Texas |
| Pardus Oil & Gas Operating, LP | Texas |
Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We have issued our report dated March 31, 2023, with respect to the consolidated financial statements included in the Annual Report of Empire Petroleum Corporation on Form 10-K for the year ended December 31, 2022. We consent to the incorporation by reference of said report in the Registration Statements of Empire Petroleum Corporation on Form S-3 (File No. 333-260570) and on Forms S-8 (File No. 333-261364 and File No. 333-267220).
/s/ GRANT THORNTON LLP
Tulsa,
Oklahoma
March 31, 2023
Exhibit 23.2
Consent of Independent Registered Public Accounting Firm
We consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-260570) and Form S-8 (No. 333-267220 and No. 333-261364) of Empire Petroleum Corporation (the “Company”), of our report dated March 31, 2022, relating to the consolidated financial statements of the Company as of and for the year ended December 31, 2021, appearing in this Annual Report on Form 10-K of the Company for the year ended December 31, 2022.
/s/ Moss Adams LLP
Dallas, Texas
March 31, 2023
Exhibit 23.3
CONSENT OF CAWLEY, GILLESPIE & ASSOCIATES, INC.
We consent to the incorporation by reference in the registration statements (File Nos. 333- 261364 and 333-267220) on Form S-8 and the registration statement (File No. 333-260570) on Form S-3 of Empire Petroleum Corporation (the “Company”) of our report for the Company and the references to our firm and said report, in the context in which they appear, in this Annual Report on Form 10-K of the Company for the year ended December 31, 2022 (this “Form 10-K”), which report is included as an exhibit to this Form 10-K.
Respectfully submitted,
CAWLEY, GILLESPIE & ASSOCIATES, INC.
Texas Registered Engineering Firm F-693
Fort Worth, Texas
March 31, 2023
Exhibit 31.1
CERTIFICATION
I, Michael R. Morrisett, certify that:
| 1. | I have reviewed this annual report on Form 10-K of Empire Petroleum Corporation; |
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
| 4. | The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
| (a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
| (b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
| (c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
| (d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
| 5. | The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
| (a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
| (b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
| March 31, 2023 | /s/ Michael R. Morrisett | |
| Michael R. Morrisett President and Chief Executive Officer |
Exhibit 31.2
CERTIFICATION
I, Michael R. Morrisett, certify that:
| 1. | I have reviewed this annual report on Form 10-K of Empire Petroleum Corporation; |
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
| 4. | The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
| (a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
| (b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
| (c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
| (d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
| 5. | The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
| (a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
| (b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
| March 31, 2023 | /s/ Michael R. Morrisett | |
Michael R. Morrisett President and
Chief Executive Officer |
Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the annual report of Empire Petroleum Corporation (the “Company”) on Form 10-K for the year ended December 31, 2022, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael R. Morrisett, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
| (1) | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
| (2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
| March 31, 2023 | /s/ Michael R. Morrisett | |
| Michael R. Morrisett President and Chief Executive Officer |
A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.
The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report and shall not be considered filed as part of the Report.
Exhibit 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the annual report of Empire Petroleum Corporation (the “Company”) on Form 10-K for the year ended December 31, 2022, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael R. Morrisett, President and Chief Executive Officer (principal financial officer) of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
| (1) | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
| (2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
| March 31, 2023 | /s/ Michael R. Morrisett | |
| Michael R. Morrisett President and Chief Executive Officer (principal financial officer) |
A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.
The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report and shall not be considered filed as part of the Report.
EXHIBIT 99.1
March 14, 2023
Mr. Michael R. Morrisett
President
Empire Petroleum Corporation
2200 S. Utica Place, Suite 150
Tulsa, OK 74114
| Re: | Evaluation Summary | |
| Empire Petroleum Corporation Interests | ||
| Various States | ||
| Proved Developed Producing Reserves | ||
| As of December 31, 2022 |
Dear Mr. Morrisett:
As requested, we are submitting our estimates of proved developed producing reserves and our forecasts of the resulting economics attributable to the above captioned interests in various states. It is our understanding that the proved reserve estimates shown herein constitute 100 percent of all proved reserves owned by Empire Petroleum Corporation. This report, completed on March 14, 2023, has been prepared for use in filings with the Securities and Exchange Commission (“SEC”) by Empire Petroleum Corporation. In our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.
Composite reserve estimates and economic forecasts for the proved developed producing reserves are summarized below:
| Proved | ||
| Developed | ||
| Producing | ||
| Net Reserves | ||
| Oil | - Mbbl | 8,826.4 |
| Gas | - MMcf | 12,936.4 |
| NGL | - Mbbl | 2,261.7 |
| Revenue | ||
| Oil | - M$ | 804,436.6 |
| Gas | - M$ | 54,664.7 |
| NGL | - M$ | 82,071.1 |
| Severance and | ||
| Ad Valorem Taxes | - M$ | 70,209.0 |
| Operating Expenses | - M$ | 438,945.6 |
| Investments | - M$ | 55,901.8 |
| Operating Income (BFIT) | - M$ | 376,115.9 |
| Discounted at 10.0% | - M$ | 195,429.1 |
The discounted value shown above should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc.
Evaluation Summary
As of December 31, 2022
Page 2
Hydrocarbon pricing of $6.358 per MMBtu of gas (Henry Hub spot) and $93.67 per barrel of oil/condensate (WTI spot) was applied without escalation. In accordance with the SEC guidelines, these prices were determined as an unweighted arithmetic average of the first-day-of-the-month price for the previous 12 months. The oil and gas prices were held constant and were adjusted for gravity, heating value, quality, transportation and marketing. NGL prices were forecasted as fractions of the above oil price. The adjusted volume-weighted average product prices over the life of the properties are $91.14 per barrel of oil, $4.23 per Mcf of gas and $36.29 per barrel of NGL.
Operating expenses were supplied by Empire Petroleum Corporation and reviewed for reasonableness. Severance and ad valorem taxes were scheduled based on historical rates. Neither expenses nor investments were escalated. The cost of plugging and the salvage value of equipment have been considered.
The proved reserves classifications conform to criteria of the SEC. The estimates of reserves in this report have been prepared in accordance with the definitions and disclosure guidelines set forth in the SEC Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). The reserves and economics are predicated on the regulatory agency classifications, rules, policies, laws, taxes and royalties in effect on the effective date except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions have not been considered.
The reserves were estimated using a combination of the production performance and analogy methods, in each case as we considered to be appropriate and necessary to establish the conclusions set forth herein. All reserve estimates represent our best judgment based on data available at the time of preparation and assumptions as to future economic and regulatory conditions. It should be realized that the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.
The reserve estimates were based on interpretations of factual data furnished by Empire Petroleum Corporation. Ownership interests were supplied by Empire Petroleum Corporation and were accepted as furnished. To some extent, information from public records has been used to check and/or supplement these data. The basic engineering and geological data were utilized subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. An on-site inspection of these properties has not been made nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered.
Our work-papers and related data are available for inspection and review by authorized parties.
Respectfully submitted,
CAWLEY, GILLESPIE & ASSOCIATES, INC.
Texas Registered Engineering Firm F-693
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