UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

_________________

FORM 10-K

_________________

☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2021

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

For the transition period from _____________ to _____________

_________________

Commission File Number 001-16653

EMPIRE PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

_________________

delaware		73-1238709
(State or Other Jurisdiction		(I.R.S. Employer
of Incorporation or Organization)		Identification No.)

2200 S. Utica Place, Suite 150   Tulsa, OK 74114
(Address of Principal Executive Offices) (Zip Code)

Registrant's telephone number, including area code:  (539) 444-8002

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

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock $.001 par value	EP	NYSE American

Securities registered pursuant to 12(g) of the Act:

None

(Title of class)

_________________

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

☐ Yes ☑ No

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

☐ Yes ☑ No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☑ Yes ☐ No

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

☑ Yes ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See 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 ☐	Non-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. ☐

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

☐ Yes ☑ No

The aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference by the average bid and asked price of such common equity as of the last business day of the registrant's most recently completed second fiscal quarter, was $78,937,171.

The number of shares of the registrant's common stock, $0.001 par value, outstanding as of March 15, 2022 was 19,855,107.

DOCUMENTS INCORPORATED BY REFERENCE

None.

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EMPIRE PETROLEUM CORPORATION

FORM 10-K

TABLE OF CONTENTS

		PAGE NO.
	Glossary of Certain Oil and Natural Gas Terms PART I	5
Item 1.	Business	6
Item 1A.	Risk Factors	10
Item 1B.	Unresolved Staff Comments	20
Item 2.	Properties	20
Item 3.	Legal Proceedings	20
Item 4.	Mine Safety Disclosures	20
	PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	21
Item 6.	Reserved	21
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	21
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	27
Item 8.	Financial Statements and Supplementary Data	27
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	27
Item 9A.	Controls and Procedures	27
Item 9B.	Other Information	28
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	28
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	28
Item 11.	Executive Compensation	30
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	32
Item 13.	Certain Relationships and Related Transactions and Director Independence	34
Item 14.	Principal Accountant Fees and Services	34
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	35
Item 16.	Form 10-K Summary	37
	Signatures	38

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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 the Company’s 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. Such factors include, among others: general economic conditions; management’s ability to execute the Company’s business plan; changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids; the Company’s ability to replace reserves and efficiently develop current reserves; costs of operations; 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; management’s ability to integrate acquisitions; weather and environmental conditions; and the other factors discussed below and elsewhere in this Form 10-K and in other documents that we file with or furnish to the United States Securities and Exchange Commission (the “SEC”), all of which are difficult to predict. Factors that could cause results to differ materially from the results discussed in such forward-looking statements include:

the need for additional capital,

unforeseen engineering, mechanical or technological difficulties in working over wells,

operating hazards,

competition from other natural resource companies,

the fluctuations of prices for oil, natural gas, and natural gas liquids,

unanticipated reductions in the borrowing base under the credit agreement 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 world health events, including the coronavirus pandemic (“COVID-19”),

the effects of governmental and environmental regulation, and

general economic conditions and other risks described in the Company's filings with the Securities and Exchange Commission (the "SEC").

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this Annual Report on 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 pace 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.

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.

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”, and “our” refer to Empire Petroleum Corporation and its wholly-owned subsidiaries, unless context indicates otherwise.

The Company 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 have been stated at post-reverse split amounts.

On March 8, 2022, the Company’s common stock began trading on the New York Stock Exchange American (“NYSE American”) under the symbol “EP” and CUSIP 292034303. Prior to trading on the NYSE American, the Company’s common stock was accessible on the OTCQB.

Overview

Empire Petroleum Corporation is an independent energy company owner-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 North Dakota LLC (“Empire North Dakota”)

Empire New Mexico LLC d/b/a Green Tree New Mexico (“Empire New Mexico”)

Empire Texas (“Empire Texas”), consisting of the following entities:

Empire Texas 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 Utah in August 1983 and subsequently 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.

The Company’s mission is to increase shareholder value by building oil and natural gas reserves in strategic plays in the United States. To accomplish its mission, the Company plans on executing the following business strategies:

Target proved developed producing acquisitions in predictable, fields that have historically had low decline and long lives

Focus on high-quality assets that add scale and provide synergies to the Company’s existing portfolio and core areas of operation

Cost-effectively optimize well production by deploying rigorous field management programs

Reduce unit operating costs and improve margins by utilizing experienced field personnel

The Company operates as a single segment as each of its operating areas has similar economic characteristics and each meet the criteria for aggregation as defied by accounting standards related to disclosures about segments of an enterprise.

The Company has progressed through several leadership teams since its inception in 1983 and the most recent management team was installed in 2017 and its first PDP operating assets were purchased in 2018.

Properties

The Company is an independent operator in four geographic areas in the United States. As operator, the Company manages and influences production on operated properties. The Company uses a combination of experienced field personnel and third-party service providers to execute its mission. The Company’s properties have reasonably predictable production profiles and cash flows, subject to commodity price and cost fluctuations.

As is common in the industry in which the Company operates, the Company selectively participates in drilling and developmental activities in non-operated properties. Decisions to participate in non-operated properties are dependent upon the technical and economic nature of the projects and the operating expertise and historical track record of the operators.

Empire Louisiana

Empire Louisiana acquired its assets in late 2018 and has 11 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 average operated NRI of 47%.

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Empire New Mexico

Empire New Mexico was formed when the Company 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

Blinebry

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

Presence in these formations allows the Company to execute its mission in areas with sustained impressive, near-flat production rates over the last five years and capitalize on operational improvements to allow more immediate recovery of reserves.

Empire Texas

In April 2020, Empire Texas acquired 139 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.

In August 2020, Empire Texas entered into a joint development agreement with Petroleum & Independent Exploration, LLC and related entities (“PIE”). Under the terms of this agreement, 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 the Company dated August 1, 2020, whereby PIE will loan up to $2,000,000, at an interest rate of 6% per annum, maturing August 7, 2024 unless terminated earlier by PIE. Proceeds of the loan will be used for recompletion or workover of the Workover Wells. Empire Texas will assign a combined 85% working and revenue interest in the Workover Wells to PIE when work commences on a property. Of the assigned interest, 70% working and revenue interest will be used to repay the obligations under the term loan agreement. Once the term loan is repaid, PIE will reassign a 35% working and revenue interest to Empire Texas in each of the Workover Wells and retain a 50% working and revenue interest.

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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, 2021 and 2020. 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, 2021		Year ended December 31, 2020
Production and operating data:
Net production volumes:
Oil (Bbl)		333,158		164,869
Natural gas (Mcf)		622,474		139,412
Natural gas liquids (gal)		4,321,497		—
Total (Boe)		539,796		188,104

Average price per unit:
Oil (a)	$	64.52	$	42.00
Natural gas (a)	$	3.90	$	2.53
Natural gas liquids	$	0.79	$	—
Total (Boe)	$	50.61	$	38.68

Operating costs and expenses per Boe:
Oil and natural gas production	$	26.11	$	25.90
Production and ad valorem taxes	$	3.90	$	1.84
Depreciation, depletion, amortization and accretion	$	6.89	$	21.52
Impairment	$	—	$	46.10
General & administrative	$	15.68	$	39.20

(a)

Includes the effect of net cash receipts (payments on) derivatives, as applicable contracts are in place.

At December 31, 2021, the Company has approximately 1,100 operated wells. At December 31, 2020, the Company had 190 producing wells of which it operated 156.

The Company has no operated wells in process as of December 31, 2021, or 2020 and had no drilling activity during the year with the exception of four non-operated wells.

The Company has no delivery commitments for oil or natural gas.

Oil and Natural Gas Reserves

The Company engaged an independent petroleum engineering firm, CG&A, to prepare its annual reserve estimates and has relied 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 and The Society of Petroleum Evaluation Engineers.

Brian Weatherl, Vice President of Engineering, is responsible for 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 Company maintains adequate and effective internal controls over the reserves estimation process as well as the underlying data upon which reserve estimates are based. 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 Company 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. Internal controls over financial reporting are assessed for effectiveness annually using criteria set forth in “Internal Control – Integrated Framework” (2013 version) issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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. The Company’s 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 Company 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 Company 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.

Net proved reserves were calculated using flat, twelve-month average commodity index prices for each month 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 $64.31 per barrel and $7.34 per Mcf were utilized at December 31, 2021. Natural gas pricing includes prices received for NGLs during the year. Due to the inherent uncertainty associated with estimating NGLs, no NGL volumes were included in the reserve report.

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The following table represents the Company’s oil and natural gas reserves at December 31, 2021.

	Oil	Natural Gas
	(Mbbl)	(MMcf)
Proved developed	8,448	11,205

The following table represents the Company’s oil and natural gas reserves at December 31, 2020. Pricing was in accordance with SEC guidelines and was $32.94 per barrel and $1.41 per Mcf.

	Oil	Natural Gas
	(Mbbl)	(MMcf)
Proved developed	3,331	940

The Company’s primary mission is to optimize existing producing properties; as such, there are no reserves estimated for undeveloped properties, though the Company owns acreage that can be drilled in the future and is also a non-operator WI owner on acreage subject to future drilling activities.

Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that 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 the Company’s external engineers to ensure the integrity, accuracy, and timeliness of data that is furnished to them for their reserve estimation process.

COVID-19

Despite recoveries in commodity prices, recent surges from COVID-19 variants continue to impact the global economy, disrupt global supply chains, and have the potential to create significant volatility and disruption of financial and commodity markets. The extent of the impact of the COVID-19 pandemic on the Company’s operational and financial performance, including its ability to execute business strategies and initiatives in the expected timeframes, is uncertain and depends on various factors, including how the pandemic and measures taken in response to its effects impact the demand for oil and natural gas, the availability of personnel, equipment, and services critical the Company’s ability to operate its properties and the impact of potential governmental restrictions. There is uncertainty regarding the extent and duration of any disruption.

As a producer of oil, natural gas, and NGLs, the Company is recognized as an essential business under various federal, state, and local regulations related to the COVID-19 pandemic. The Company has continued to operate as permitted while working to protect the health and safety of employees.

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.

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 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 2021, 63% revenues from oil, natural gas, and NGL sales were to four customers. For 2020, revenues from oil and natural gas sales to four customers accounted for 95% of our total operating revenues. 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 region.

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 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.

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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 fluctuation, 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 gas is volatile, subject to speculative movement and depends upon numerous factors beyond the control of the Company, 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 gas. If the market price for oil and gas remains depressed in the future, it could have a material adverse effect on the Company's ability to raise additional capital necessary to finance operations. Lower oil and gas prices may also reduce the amount of oil and gas, if any, that can be produced economically from the Company's properties. The Company anticipates that the prices of oil and gas will fluctuate in the near future.

Regulation

The oil and 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 gas industry is constantly changing. Numerous federal and state departments and agencies have issued rules and regulations applicable to the oil and 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 gas resources; and, in some cases, rates of production. The heavy and increasing regulatory burdens on the oil and gas industry increase the Company's cost of doing business and, consequently, affect profitability.

The oil and 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 the Company fails to comply or if any contamination results from the Company's operations.

Employees

At December 31, 2021, the Company had thirty-one full-time employees, not including contract personnel and outsourced service providers. The Company’s 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, OK, with field offices in North Dakota, Texas, and New Mexico.

ITEM 1A. RISK FACTORS.

The Company’s 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 operations or financial position. Risks and uncertainties discussed below are not a comprehensive listing of those faced by the Company. Additional risks not presently known or that are deemed immaterial may also affect the Company. 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.

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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. Our non-GAAP (Generally Accepted Accounting Principles) financial measure, PV-10, 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 it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. Accordingly, estimates included herein 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 our company 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 fair value of proved reserves.

Estimates of proved reserves and future net cash flows are not precise. The actual quantities of 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.

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 herein 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.

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Unless reserves are replaced, production and estimated reserves will decline, which may adversely affect the Company’s 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 the Company’s success in efficiently developing and exploiting current properties and economically finding or acquiring additional recoverable reserves. The Company may not be able to develop, find or acquire additional reserves to replace its current and future production at acceptable costs. If the Company is unable to replace our current and future production, cash flows and the value of reserves may decrease, adversely affecting the Company’s business, financial condition and results of operations.

Financing

The Company has indebtedness and may incur substantially more debt. Higher levels of indebtedness make the Company more vulnerable to economic downturn and adverse business developments.

The Company’s subsidiaries Empire Louisiana and Empire North Dakota had approximately $7.1 million of outstanding aggregate principal indebtedness at December 31, 2021. At December 31, 2021, commitments from our financial institution (as amended) were $7.4 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 our indebtedness. If the Company does 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, the Company uses a portion of its 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 the Company operates. Indebtedness under the Credit Facility is at a variable interest rate, and so a rise in interest rates will generate greater interest expense.

The Company may incur substantially more debt in the future. The Credit Facility contains restrictions on incurrence of additional indebtedness.

Increases in the level of indebtedness could have adverse effects on the Company’s 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.

The Company’s ability to meet its debt obligations and reduce its 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.

The 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 partially through borrowings under the Credit Facility. 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 the Company is 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;

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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 the Company’s credit ratings; and

proved reserves.

The Company 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 the Company’s 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 the Company’s 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 the Company’s 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 the Company is unable to comply with the covenants in its debt agreement, there could be a default under the terms of the agreement, which could result in an acceleration of payment of funds that we have borrowed.

The Company’s ability to meet its 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, 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 our Senior Revolver Loan Agreement to avoid being in default. If we breach our covenants and cannot obtain a waiver from the required lenders, we would be in default and the lenders could exercise their rights, as described above, and we could be forced into bankruptcy or liquidation.

A negative shift in stakeholder sentiment towards the oil and 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 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 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.

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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. 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 the ongoing impact of COVID-19;

the price and quantity of imports of foreign oil and natural gas;

political conditions, including 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.

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. The recent volatility in the price of oil has forced the Company, 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 the Company and its 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, 2021, 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 this area 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.

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The Company's insurance policies may not adequately protect the Company against certain unforeseen risks.

In accordance with customary industry practice, the Company maintains insurance against some, but not all, of the risks described herein. There can be no assurance that any insurance will be adequate to cover the Company's losses or liabilities. The Company cannot predict the continued availability of insurance, or its availability at premium levels that justify its purchase.

The Company is subject to various environmental risks, and governmental regulation relating to environmental matters.

The Company is 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 the Company 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 the Company's financial condition or results of operations, there can be no assurance that the Company will not be required to make material expenditures in the future. Moreover, the Company anticipates that such laws and regulations will become increasingly stringent in the future, which could lead to material costs for environmental compliance and remediation by the Company. Any failure by the Company to obtain required permits for, control the use of, or adequately restrict the discharge of hazardous substances under present or future regulations could subject the Company to substantial liability or could cause its operations to be suspended. Such liability or suspension of operations could have a material adverse effect on the Company's business, financial condition and results of operations.

The Company's activities are subject to extensive governmental regulation. Oil and 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 gas. In addition, the production, handling, storage, transportation and disposal of oil and gas, by-products thereof and other substances and materials produced or used in connection with oil and 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 the operations of the Company. There can be no assurance that the trend of more expansive and stricter environmental legislation and regulations will not continue.

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

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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.

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 CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for 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, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. The federal regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. In November 2021, the EPA proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. The EPA is currently seeking public comments on its proposal, which the EPA hopes to finalize by the end of 2022. Once finalized, the regulations will also need to be incorporated in state implementation plans and approved by EPA. 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 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. 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

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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 commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital 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. More recently, 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.

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 toa 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.

The Company could be adversely affected by increased costs of service providers utilized by the Company.

In accordance with customary industry practice, the Company has 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 the Company's production costs.

Our ability to use our existing net operating loss carryforwards or other tax attributes could be limited.

At December 31, 2021, we had approximately $20.7 million of federal NOL carryforwards available to 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.

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.

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of GHGs under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis, including GHG emissions resulting from the completion and workover operations of hydraulically fractured oil wells. Recent federal regulatory action with respect to climate change has focused on methane emissions. For example, in June 2016, the EPA finalized new air emission controls for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The final rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions, and also imposes leak detection and repair requirements on operators. However, in June 2017, the EPA proposed a two year stay of fugitive emissions monitoring requirements, pneumatic pump standards, and closed vent system certification requirements in the 2016 rule while it reconsiders these aspects of the rule. Additionally, on September 11, 2018, the EPA proposed targeted improvements to the 2016 rule, including amendments to the rule’s fugitive emissions monitoring requirements, and expects to “significantly reduce” the regulatory burden of the rule in doing so. The BLM finalized similar rules in November 2016 that limit methane emissions from new and existing oil and natural gas operations on federal lands through limitations on the venting and flaring of gas, as well as enhanced leak detection and repair requirements but then finalized a revised rule in 2018 which scaled back the waste prevention requirements of the 2016 rule. Environmental groups have sued in federal district court to challenge the legality of aspects of the revised rule, and the outcome of this litigation is currently uncertain. These methane emission rules have the potential to increase our compliance costs.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce emissions of GHGs in recent years. In the absence of Congressional action, many states have established rules aimed at reducing GHG emissions, including GHG cap and trade programs. Most of these cap-and-trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and natural gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. In the future, the United States may also choose to adhere to international agreements targeting GHG reductions.

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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 the Company is 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.

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.

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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.

The Company does not expect to declare or pay any dividends in the foreseeable future.

The Company has not declared or paid any dividends on its Common Stock. The Company currently intends to retain future earnings to fund the development and growth of its business, to repay indebtedness and for general corporate purposes, and therefore, does not anticipate paying any cash dividends on its 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 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.

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, the Company may be involved in litigation and claims arising from operations. As of December 31, 2021, 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 the 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

The Company's Common Stock is traded on the NYSE American under the symbol "EP".

Stockholders

At both December 31, 2021, and March 31, 2022, there were approximately 900 stockholders of record of the Company's Common Stock.

Dividends

The Company has never paid cash dividends on its Common Stock. The Company intends to retain future earnings for use in its business and, therefore, does not anticipate paying cash dividends on its Common Stock in the foreseeable future. Future payment of dividends will depend upon, but not be limited to, the Company’s 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 the Company for the year ended December 31, 2021.

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

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

The Company's primary business is the exploration and development of oil and gas interests. The Company has incurred significant losses from operations, and there is no assurance that it will achieve profitability or obtain funds necessary to finance its future operations.

The Company seeks to increase shareholder value by growing reserves, production, revenues, and cash flow from operating activities by executing its 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 its business, as operating cash flow considers the cash expenses incurred during the period and excludes non-cash expenditures not related directly to the Company’s operations.

Business Strategy

The Company’s business strategy is to obtain long-term growth in reserves and cash flow on a cost-effective basis utilizing experienced personnel throughout the Company. 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) (the “Seller’) to acquire, among other things, certain oil and natural gas properties in New Mexico. The purchase price was $17,800,000 subject to customary adjustments. The transaction closed on May 14, 2021 with an effective date of January 1, 2021. For more information about the transaction, refer to the financial statements and footnotes incorporated by reference herein.

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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,
	2021			2020			Variance			Variance %

Oil revenues	$	22,326,289		$	5,452,187			16,874,102			309	%
Natural gas revenues		2,593,081			347,355			2,245,726			647	%
NGL revenues		3,396,097			100,718			3,295,379			3272	%
Total revenues from product sales		28,315,467			5,900,260

Lease operating expense		14,095,708			4,871,755			9,223,953			189	%
Production and ad valorem taxes		2,102,772			346,101			1,756,671			508	%
Depreciation, depletion, amortization and accretion		3,716,754			4,047,877			(331,123	)		-8	%
Impairment expense		—			8,671,303			(8,671,303	)		-100	%
General and administrative expense (excluding stock-based compensation)		7,366,061			5,424,304			1,941,757			36	%
Stock-based compensation		1,095,970			1,949,500			(853,530	)		-44	%
Cash-based interest expense		436,053			521,187			(85,134	)		-16	%
Non-cash interest expense		8,164,646			—			8,164,646			100	%

Operating Loss		(473,370	)		(17,583,006	)		17,109,636			-97	%
Net Loss		(18,614,962	)		(16,835,433	)		1,779,529			11	%

Revenues

Revenues increased as a result of more volumes produced from legacy assets due to successful execution of the Company’s mission to cost-effectively produce more volumes paired with the XTO acquisition’s revenues and volumes brought online from efforts to make the field produce more volumes combined with favorable pricing environments in the Company’s core operating areas. Approximately $11.2 million in oil revenues, $1.7 million in gas revenue, and $3.1 million in NGL revenue was attributed to production acquired with the XTO acquisition.

Lease Operating Expense and Taxes

Lease operating expense rose with the XTO acquisition and in response to the Company’s execution of its mission to increase production in its legacy assets. The Company has worked to cost-effectively increase production throughout its asset base utilizing experienced personnel and third-party service providers. Production and ad valorem taxes have increased as a direct result of the XTO acquisition’s properties and increased volumes produced and sold. The acquisition of New Mexico assets accounted for approximately $5.0 million of the increase in lease operating expenses and $1.3 million of the increase in production and ad valorem taxes.

Depreciation, Depletion, Amortization and Accretion and Impairment

There were no indicators of impairment on the Company’s properties at year-end, primarily due to favorable futures pricing at December 31, 2021. Due to favorable pricing realized throughout 2021 and the addition of PDP reserves in New Mexico, DD&A expense decline year-over-year from approximately 13% in 2020 to 6% in 2021.

General and Administrative Expense

The Company’s implemented a new Board of Directors compensation plan in 2021 resulting in board compensation paid of approximately $475,000 in 2021, exclusive of stock-based compensation received. Fees paid for legal and outsourced services increased by approximately $425,000 as a direct result of acquisition-related work, SEC filings related to the Company’s operations, and the Company’s successful uplisting from the OTCQB to be freely traded on the NYSE American. Outsourced accounting fees increased by approximately $375,000 as additional work was required to integrate the New Mexico assets into the existing accounting system as well as additional resources required to perform routine accounting services on the new assets. Also included in general and administrative expenses is $989,000 in non-cash right to buy costs related to the unsecured notes payable discussed in the Related Party Transactions note below.

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The Company utilizes stock-based compensation to compensate members of management and retain talented personnel. The Company anticipates stock-based compensation to continue to be utilized in 2022 and beyond to attract and retain talented personnel.

Interest Expense

Cash-based interest expense declined with a corresponding decrease in the Company’s Credit Facility. The Company has minimal interest-bearing vehicle and equipment notes payable.

Non-cash interest expense is fully attributable to the related party notes payable as described in Related Party Transactions below.

Liquidity

As of December 31, 2021, the Company had approximately $3.6 million cash on hand and approximately $300,000 available on its Credit Facility. The Company expects to incur costs related to future oil and natural gas acquisitions for the foreseeable future. It is expected that management will use a combination of cash flows from operations as well as seeking additional debt and equity funding for these acquisitions and to fund ongoing operations.

Working Capital

Working capital (presented below) was $1.1 million as of December 31, 2021 compared to a deficit of $3.9 million as of December 31, 2020, representing a change of approximately $5 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, 2021, as well as the stronger pricing environment in 2021.

	December 31,
	2021		2020
Current Assets		13,118,020		2,222,533
Current Liabilities		12,054,487		6,072,710
Working Capital (Deficit)		1,063,533		(3,850,177	)

Cash Flows

	Year Ended December 31,
Cash flows provided by (used in):	2021			2020			Variance
Operating activities	$	3,170,282		$	(1,723,257	)	$	4,893,539
Investing activities		(24,716,878	)		856,290			(25,573,168	)
Financing activities		25,000,772			1,024,662			23,976,110

Cash Flows from Operating Activities

The Company 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. Ongoing operations from core assets contributed to cash flows provided by operating activities for the year ended December 31, 2021.

Cash Flows from Investing Activities

Cash flows from investing activities primarily increased due to the XTO acquisition that occurred in May 2021 and established the Company in the state of New Mexico, the Company’s largest single acquisition to date that resulted in cash outflows of approximately $17.9 million. The Company also participated in the drilling of four non-operated wells through its Empire North Dakota subsidiary that had a cash outflow of approximately $2.5 million for the year ended December 31, 2021. As part of the XTO acquisition, the Company entered into an agreement to create a sinking fund for future plugging liabilities, paying approximately $4.8 million into that fund for the year.

Cash Flows from Financing Activities

The XTO acquisition and operations executing the Company’s 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. The Company has quarterly payment obligations related to its bank debt of $300,000 per quarter in addition to minimal monthly payments for notes payable arising from the purchase of vehicles and equipment.

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Related Party Transactions

The issuance of the Secured Note and an Unsecured Note to Energy Evolution as described below are related party transactions for accounting purposes, but are not required to be disclosed under Item 13 of this Form 10-K.

Senior Secured Convertible Note

On May 14, 2021, Empire New Mexico entered into a Senior Secured Convertible Note Agreement (the “Secured Note”) in the amount of $16,250,000 with Energy Evolution Master Fund, Ltd., a related party (“Energy Evolution”). The Secured Note was collateralized by all assets of Empire New Mexico prior to its conversion to common stock in December 2021. Due to the terms of the Secured Note, the transaction had the following non-cash elements for the year ended December 31, 2021:

A debt discount of $2.2 million

$2.2 million in derivative liability considerations, including the valuation of the redemption option

Non-cash interest expense of $7.4 million

On September 29, 2021 the parties entered into a Loan Modification Agreement pursuant to which Energy Evolution exchanged $6,500,000 in principal under the Secured Note in exchange for 1,326,302 shares of common stock, warrants to purchase 500,000 shares of the Company’s common stock at $5 per share and amended certain terms of the remaining $5,700,000 of principal under the Secured Note.

On December 30, 2021, the Secured Note was amended to allow full conversion of the remaining balance and Energy Evolution converted 100% of the remaining principal ($5.7 million) and accrued interest ($55,000) outstanding at that date into 1,154,085 shares of the Company’s common stock.

Unsecured Convertible Notes

In May 2021 the Empire New Mexico entered into $3,243,000 of Unsecured Convertible Notes (the “Unsecured Notes”) with a group of accredited investors, including the Company’s related party Energy Evolution, constituting $1,500,000 of the total Unsecured Convertible Notes. The Unsecured Notes had a maturity of May 9, 2022 with a single payment and interest at 5%. The Unsecured Note holders had the ability to convert their notes to common stock of the Company at the lesser of $5 per share or the price per share offered by the Company if the Company has a future capital raise for an aggregate 648,600 shares of common stock (without giving effect to any interest that may be converted). At December 31, 2021 $2,918,000 of the Unsecured Notes had been converted into 583,600 shares of common stock of the Company and 5,594 shares of common stock have been issued as payment for accrued interest on the Unsecured Note. The remaining Unsecured Notes in the amount of $325,000 were repaid in September 2021. Amortization of these notes was recorded as a non-cash interest expense of approximately $545,000.

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 $544,824. The discount associated with these transactions is amortized under the interest method and resulted in interest expense of $544,824 for the year ended December 31, 2021.

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 40% of such investor’s principal balance under its Unsecured Convertible Note at $3 per share (the “right to buy”). Energy Evolution exercised its right to buy 150,000 shares of the Company’s common stock. In conjunction with the conversion of the Unsecured Notes, each of the Company’s Chief Executive Officer and President partially exercised a warrant and options to purchase 160,900 shares at an exercise price of $1.00 and $1.32 respectively. The Company determined that offering the “right to buy” shares resulted in a non-cash expense of $989,155 of the Company based on the fair value of contributions made by the Company’s Chief Executive Officer and President on its behalf. The fair value of the “right to buy” shares was determined using a Black-Scholes model. The expense is included in General and Administrative in the Consolidated Statement of Operations.

Effective Tax Rate

For all periods presented, the Company's effective tax rate is 0%. The Company has generated net operating losses since inception, which would normally reflect a tax benefit in the statement of operations and a deferred asset on the balance sheet. However, because of the current uncertainty as to the Company's ability to achieve profitability, a valuation reserve has been established that offsets the amount of any tax benefit available for each period presented in the statements of operations.

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OFF-BALANCE SHEET ARRANGEMENTS

The Company does not have any off-balance sheet arrangements.

CRITICAL ACCOUNTING POLICIES AND 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 and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Because estimates and assumptions require significant judgment, future actual results could differ from those estimates and could have a significant impact on the Company's results of operations, financial position and cash flows. The Company re-evaluates its estimates and assumptions at least on a quarterly basis. The following policies may involve a higher degree of estimation and assumption:

Oil and Natural Gas Properties

The Company uses 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. Exploration costs, including unsuccessful exploratory wells, geological and geophysical are charged to operations as incurred. Depreciation, depletion and amortization of the leasehold and development costs that are capitalized for proved oil and natural gas properties are computed using the units-of-production method, at the field level, based on total proved reserves and proved developed reserves, respectively, as estimated by independent petroleum engineers. Oil and natural gas properties are periodically assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cashflows expected to be generated by an asset group, but at least annually. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a state-by-state basis. All of our properties are located within the continental United States.

All costs related to unsuccessful exploratory wells are expensed when such wells are determined to be non-productive and other exploration costs, including geological and geophysical costs, are expensed as incurred. The application of the successful efforts method of accounting requires management's judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. The evaluation of oil and gas leasehold acquisition costs requires management's judgment to estimate the fair value of exploratory costs related to drilling activity in a given area.

Impairment of Oil and Gas Properties

Management’s assessment of the results of 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 economic to develop some of these unproved properties.

Oil and Natural Gas Reserve Quantities

Reserve quantities and the related estimates of future net cash flows affect periodic calculations of depletion, impairment of oil and natural gas properties, and asset retirement obligations. 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.

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 the Company’s estimated proved producing reserve quantities and their related future net cash flows as of December 31, 2021. 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. Management makes changes to depletion rates, impairment calculations, and asset retirement obligations in the same period that changes to reserve estimates are made.

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Depreciation, Depletion and Amortization

The rate used to calculate and record DD&A is dependent upon estimates of total proved developed reserves, which incorporate various assumptions and future projections. If the estimates of total proved or proved developed reserves decline, DD&A expense increases. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to operate wells due to higher cost fields. Management is unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of executing the Company’s mission as well as future economic conditions.

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. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the field.

Stock-Based Compensation

The Company recognized stock-based compensation expense associated with restricted stock units, which consists of time-based awards. 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 Company’s common stock, $0.001 par value per share on the grant date. The Company classifies grants to be settled in shares as equity awards.

Income Taxes and Uncertain Tax Positions

The Company’s 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. The effective tax rate for financial statement purposes is 0% for all periods presented.

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, 2021 and 2020, 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. The Company has no uncertain tax positions at either December 31, 2021 or December 31, 2020.

Revenue Recognition

The Company predominantly derives its revenue from the sale of produced oil, natural gas and NGLs. Revenues are recognized when the recognition criteria of FASB ASC Topic 606, Revenue from Contracts with Customers, are met, which generally occurs at the point in which title passes to the customers. We receive payment from one to three months after delivery. At the end of each quarter, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received. Historically, differences have been insignificant.

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ITEM 7A.   

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

The Company is a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and is 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.

The Company’s 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.

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 Chief Executive Officer and Chief 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, 2021 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 interim financial statements will not be prevented or detected on a timely basis. 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, 2021 and on the date of this Report, its internal control over financial reporting is not effective.

Management’s Plant 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, including the hiring of our Chief Accounting Officer in October 2021 and will continue to increase our accounting and financial reporting capacity to effectively gather, analyze and review information related to financial reporting in a timely manner. However, the implemented and enhanced controls have not operated for a sufficient period of time to demonstrate that the material weakness was remediated as of, or subsequent to, December 31, 2021. 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 2021 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.

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ITEM 9B.   

OTHER INFORMATION.

None.

ITEM 9C.    

DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS.

Not applicable.

PART III

ITEM 10.    

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

The following lists the directors and executive officers of the Company:

Name	Age	Position
Thomas W. Pritchard	60	Chief Executive Officer and Director
Michael R. Morrisett	58	President and Director
Eugene J. Sweeney	54	Chief Operating Officer
Anthony N. Kamin	61	Director and Co-Chairman of the Board
Phil E. Mulacek	61	Director and Co-Chairman of the Board
Benjamin J. Marchive II	42	Director
Mason H. Matschke	59	Director

Directors hold office until their successors are elected by the stockholders of the Company and qualified. Executive officers serve at the pleasure of the Board of Directors.

Recommendation of Nominees to the Company's Board of Directors

The Company’s Board of Directors does not have a nominating committee. On November 19, 2021, the Company’s Board adopted resolutions requiring the independent directors of the Board (the “Independent Directors”) to participate in the consideration of director nominees and recommend for the Board’s selection the director nominees. The Independent Directors will consider director candidates submitted to them by other directors, employees and stockholders. The Independent Directors may engage professional search firms to assist them in identifying and evaluating potential candidates. Any stockholder recommendations of candidates proposed for consideration by the Independent Directors should include the candidate’s name and qualifications for director, reasons for the recommendation and the candidate’s written consent to being considered as a director nominee and should be addressed to: Attention: Independent Directors, c/o Secretary, 2200 S. Utica Place, Suite 150, Tulsa, Oklahoma 74114. The Independent Directors may require the stockholder submitting the recommendation or the recommended candidate to furnish such other information as the Independent Directors may reasonably request. In addition, the Company’s Amended and Restated Bylaws provide a process for stockholders to nominate directors for consideration at a meeting of stockholders. In considering prospective nominees for the Board, the Independent Directors will

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endeavor to find individuals of high integrity who have a solid record of accomplishment in their chosen fields and who possess the qualifications, qualities and skills to effectively represent the best interests of all stockholders. Candidates are selected for their ability to exercise good judgment and provide practical insights and diverse perspectives. The Independent Directors consider the following qualifications at a minimum to be required in recommending to the Board potential new Board members or the continued service of existing members:

an attained position of leadership in the candidate’s field of endeavor;

business and/or financial expertise;

integrity;

objectivity;

demonstrated exercise of sound business judgment;

expertise relevant to Empire Petroleum’s lines of business;

corporate governance experience;

ability to serve the interests of all stockholders;

ability to devote the time, energy and attention as may be necessary to properly discharge his or her responsibilities as a director; and

independence; at least 50% of the Board shall consist of independent directors, as defined in the rules of the NYSE American.

Other than the foregoing, there are no stated minimum criteria for director nominees, although the Independent Directors may also consider such other factors as they may deem are in the best interests of the Company and its stockholders. When considering potential nominees for the Board, the Independent Directors will consider the criteria above and each potential nominee’s individual skills and qualifications in context of the current composition of the Board and needs of the Board at such time. In connection therewith, the Independent Directors will consider diversity in professional background, experience, expertise, perspective, age, gender and ethnicity with respect to Board composition as a whole, although the Board does not have a specific diversity policy. With respect to diversity, particular emphasis is placed on identifying candidates whose skills and characteristics complement and augment the make-up of the Board as a whole and the needs of the Board given the circumstances of the Company. If the Company is legally required by contract or otherwise to provide third parties with the ability to nominate and/or appoint directors (e.g., the Company’s Series A Voting Preferred Stock), the selection and nomination of such directors is not subject to the foregoing process.

Identification of Audit Committee; Audit Committee Financial Expert

The Company has a separately-designated standing audit committee established in accordance with section 3(a)(58)(A) of the Exchange Act. The audit committee’s members are Anthony Kamin and Mason Matschke, both of whom are independent under the current director independence standards of the NYSE American. The Board has determined the Company does not have an audit committee financial expert serving on its audit committee. The Board has determined that both Messrs. Kamin and Matschke are able to read and understand fundamental financial statements and are financially sophisticated as contemplated under the rules of the NYSE American. The Board does not have an audit committee financial expert because it has not recruited one but will periodically review the need to add an expert.

Code of Ethics

The Company has adopted a Code of Business Conduct and Ethics that applies to all of the Company's directors and employees, including the Company's principal executive officer, principal financial officer and principal accounting officer or persons performing similar functions. The Code of Business Conduct and Ethics is available on the Company’s website at https://empirepetroleumcorp.com under the “Investor Relations – Corporate Governance” caption. If the Company amends or waives a provision of the Code of Business Conduct and Ethics that applies to the principal executive officer, principal financial officer, principal accounting officer or persons performing similar functions, the Company will post the amendment or waiver at the same location on the Company’s website.

Delinquent Section 16(a) Reports

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires the Company's directors, officers, and persons who beneficially own more than 10 percent of a registered class of the Company's equity securities, to file with the SEC initial reports of ownership and reports of changes in ownership of Common Stock and other equity securities of the Company.

Based solely on a review of the reports filed with the SEC and any written representations that no other reports were required during the year ended December 31, 2021, to the Company's knowledge, all Section 16(a) filing requirements applicable to its officers, directors and greater than 10% beneficial owners during the year ended December 31, 2021 were complied with on a timely basis, except that the initial report for (a) each of Messrs. Marchive and Matschke and Energy Evolution Master Fund, Ltd. was filed late and (b) Mr. Pritchard inadvertently omitted a holding which was later reported on a year-end report on Form 5.

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ITEM 11.   

EXECUTIVE COMPENSATION.

Executive Compensation

The following table set forth certain information regarding compensation of the Company's named executive officers. The persons named below constitute all of the executive officers of the Company as of December 31, 2021. On August 18, 2021, each of Messrs. Pritchard and Morrisett entered into an Employment Agreement with the Company. For additional information regarding their employment agreements, see “Employment Agreements” below.

Name and Principal Position	Year	Salary ($)		Bonus ($)		Stock Awards		Option Awards¹ ($)		Non-Equity Incentive Plan Compensation ($)		Life Insurance Premiums Paid ($)	All Other Compensation ($)			Total ($)

Thomas W. Pritchard	2021		250,000		125,000		—		—		—	8,989		10,302	⁽³⁾		394,291
Chief Executive Officer	2020		226,667		287,750		—		779,800		—	—		174,900	⁽²⁾		1,469,117
Michael R. Morrisett	2021		250,000		125,000		—		—		—	8,902		20,987	⁽³⁾		404,889
President	2020		226,667		287,750		—		779,800		—	—		174,900	⁽²⁾		1,469,117

_______________________

¹For further information on the assumptions used in the valuation of these awards, see Note 11 included in the Notes to Consolidated Financial Statements included in this Annual Report on Form 10-K. The amounts shown do not represent the amounts paid to the executives.

² On December 31, 2020, warrant certificates issued to Messrs. Pritchard and Morrisett pursuant to which each such named executive officer had the right to acquire 125,000 shares of the Company’s common stock at an exercise price of $1.00 per share were extended so that such warrant certificates can be exercised on or before April 2, 2029 to make such grants consistent with the 2019 Stock Plan. On December 31, 2020, each of Messrs. Pritchard and Morrisett were issued options to acquire 500,000 shares of the Company’s common stock at an exercise price of $1.40 per share under the 2019 Stock Plan.

³ All Other Compensation in 2021 consists of vehicle allowances and club dues.

Director Compensation

Annual compensation for non-employee board members, as established in August 2021, is as follows:

Non-chair, non-employee board members - $80,000 per year, with pro-rata adjustments based on date of service as necessary

Chair, non-employee board members – additional $9,000 per quarter with pro-rata adjustments based on date of service as necessary

30,000 shares of the Company’s common stock granted at December 31, 2021 with pro-rata adjustments based on date of service

The Company reimburses directors for out-of-pocket expenses in connection with attending Board and committee meetings

The Company does not pay its employees who serve on the Board of Directors any additional compensation for Board membership

The following table shows total compensation received in 2021 by each of the Company’s non-employee directors.

Name	Fees Earned or Paid in Cash ($)	Stock Awards¹ ($)	Total ($)
Anthony N. Kamin	116,000	—	116,000
Phil E. Mulacek	23,200	—	23,200
Benjamin J. Marchive II	16,000	—	16,000
Mason H. Matchske	53,333	—	53,333

¹ As of December 31, 2021, Mr. Kamin had outstanding options to acquire 75,000 shares related to a 2020 grant date.

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Outstanding Equity Awards at December 31, 2021

The following table sets forth certain information regarding outstanding equity awards of the Company's named executive officers.

	Option Awards
Name	Number of securities underlying unexercised options (#) exercisable	Number of securities underlying unexercised options (#) unexercisable	Equity incentive plan awards: Number of securities underlying unexercised unearned options (#)	Option Exercise Price ($)	Option Expiration Date
Thomas Pritchard	589,100	—	—	1.32	4/2/2029
	500,000	—	—	1.40	12/31/2030

SEC Form 10-K filed by Empire Petroleum Corporation