SEC Filing - Evolution Petroleum Corporation

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended March 31, 2024


☐	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 001-32942

EVOLUTION PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Nevada

41-1781991

(State or other jurisdiction of
incorporation or organization)

(IRS Employer

Identification No.)

1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079

(Address of principal executive offices and zip code)

(713) 935-0122

(Registrant’s telephone number, including area code)

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, $0.001 par value	EPM	NYSE American

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: ☐

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 definition 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 is a shell company (as defined in Rule 12b-2 of the Exchange Act.). Yes: ☐ No: ☒

At May 3, 2024, 33,357,632 shares of the Registrant’s Common Stock, $0.001 par value per share, were outstanding.

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EVOLUTION PETROLEUM CORPORATION

TABLE OF CONTENTS


Forward-Looking Statements		2
PART I.	FINANCIAL INFORMATION	4
Item 1.	Condensed Consolidated Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets (Unaudited) as of March 31, 2024 and June 30, 2023	4
	Condensed Consolidated Statements of Operations (Unaudited) for the three and nine months ended March 31, 2024 and 2023	5
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the nine months ended March 31, 2024 and 2023	6
	Condensed Consolidated Statements of Changes in Stockholders’ Equity (Unaudited) for the three and nine months ended March 31, 2024 and 2023	7
	Notes to Unaudited Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosures about Market Risks	40
Item 4.	Controls and Procedures	40
PART II. OTHER INFORMATION		41
Item 1.	Legal Proceedings	41
Item 1A.	Risk Factors	41
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 3.	Defaults Upon Senior Securities	42
Item 4.	Mine Safety Disclosures	42
Item 5.	Other Information	42
Item 6.	Exhibits	42
	Signatures	43

We use the terms, “EPM,” “Company,” “we,” “us,” and “our” to refer to Evolution Petroleum Corporation, and unless the context otherwise requires, its wholly-owned subsidiaries.

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FORWARD-LOOKING STATEMENTS

This Form 10-Q and the information referenced herein contains forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, except for statements of historical fact, are forward-looking statements. The words “plan,” “expect,” “project,” “estimate,” “may,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words or phrases. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors, which may include, but are not limited to, the following:

●

our expectations of plans, strategies and objectives, including anticipated development activity and capital spending;

●

our capital allocation strategy, capital structure, anticipated sources of funding, growth in long-term shareholder value and ability to preserve balance sheet strength;

●

the benefits of our multi-basin portfolio, including operational and commodity flexibility;

●

our ability to maximize cash flow and the application of excess cash flows to reduce long-term debt, pay dividends and repurchase shares pursuant to our share repurchase program;

●

estimates of our oil, natural gas and natural gas liquids (“NGLs”) production and commodity mix;

●

anticipated oil, natural gas and NGL prices;

●

anticipated drilling and completions activity;

●

estimates of our oil, natural gas and NGL reserves and recoverable quantities;

●

our ability to access credit facilities and other sources of liquidity to meet financial obligations throughout commodity price cycles;

●

limitations on our ability to obtain funding based on environmental, social, and corporate governance (“ESG”) performance;

●

future interest expense;

●

our ability to manage debt and financial ratios, finance growth and comply with financial covenants;

●

the implementation and outcomes of risk management programs, including exposure to commodity price and interest rate fluctuations, the volume of oil and natural gas production hedged, and the markets or physical sales locations hedged;

●

the impact of changes in federal, state, provincial and local, rules and regulations;

●

anticipated compliance with current or proposed environmental requirements, including the costs thereof;

●

the possible impact of greenhouse gas (“GHG”) emissions limitations and renewable energy incentives;

●

adequacy of provisions for abandonment and site reclamation costs;

●

our operational and financial flexibility, discipline and ability to respond to evolving market conditions;

●

the declaration and payment of future dividends and any anticipated repurchase of our outstanding common shares;

●

the adequacy of our provision for taxes and legal claims;

●

our ability to manage cost inflation and expected cost structures, including expected operating, transportation, processing and labor expenses;

●

our competitiveness relative to our peers, including with respect to capital, materials, people, assets and production;

●

oil, natural gas and NGL inventories and global demand for oil, natural gas and NGLs;

●

the outlook of the oil and natural gas industry generally, including impacts from changes to the geopolitical environment;

●

adverse weather events;

●

anticipated staffing levels;

●

anticipated payments related to our commitments, obligations and contingencies, and the ability to satisfy the same; and

●

the possible impact of accounting and tax pronouncements, rule changes and standards.

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Readers are cautioned against unduly relying on forward-looking statements which, by their nature, involve numerous assumptions and are subject to both known and unknown risks and uncertainties (many of which are beyond our control) that may cause actual events or results to differ materially and/or adversely from those expressed or implied, which include, but are not limited to, the following assumptions:

●

future commodity prices and basis differentials;

●

our ability to access credit facilities and shelf prospectuses;

●

assumptions contained in our corporate guidance;

●

the availability of attractive commodity or financial hedges and the enforceability of risk management programs;

●

expectations that counterparties will fulfill their obligations pursuant to gathering, processing, transportation and marketing agreements;

●

access to adequate gathering, transportation, processing and storage facilities;

●

assumed tax, royalty and regulatory regimes;

●

expectations and projections made in light of, and generally consistent with, our historical experience and our perception of historical industry trends; and

●

the other assumptions contained herein.

Readers are cautioned that the assumptions, risks and uncertainties referenced above, and in the other documents incorporated herein by reference (if any), are not exhaustive. Although we believe the expectations represented by our forward-looking statements are reasonable based on the information available to us as of the date such statements are made, forward-looking statements are only predictions and statements of our current beliefs and there can be no assurance that such expectations will prove to be correct.

When considering any forward-looking statement, the reader should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil, natural gas and NGLs, operating risks and other risk factors as described under the Risk Factors section of our previously filed Annual Report on Form 10-K for the fiscal year ended June 30, 2023, as well as the other disclosures contained herein, therein, and as also may be described from time to time in future reports we file with the Securities and Exchange Commission. There also may be other factors that we cannot anticipate or that are not described in this report, generally because we do not currently perceive them to be material. Such factors could cause results to differ materially from our expectations.

Forward-looking statements speak only as of the date they are made, and we do not undertake to update these statements other than as required by law. Readers are advised, however, to review any further disclosures we make on related subjects in our filings with the Securities and Exchange Commission.

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Part I. FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

EVOLUTION PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share amounts)


	March 31, 2024		June 30, 2023
Assets
Current assets
Cash and cash equivalents	$	3,067	$	11,034
Receivables from crude oil, natural gas, and natural gas liquids revenues		13,368		7,884
Derivative contract assets		347		—
Prepaid expenses and other current assets		6,275		2,277
Total current assets		23,057		21,195
Property and equipment, net of depletion, depreciation, and impairment
Oil and natural gas properties, net—full-cost method of accounting, of which none were excluded from amortization		142,157		105,781

Other assets		1,318		1,341
Total assets	$	166,532	$	128,317
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable	$	8,096	$	5,891
Accrued liabilities and other		5,985		6,027
Derivative contract liabilities		1,410		—
State and federal taxes payable		—		365
Total current liabilities		15,491		12,283
Long term liabilities
Senior secured credit facility		42,500		—
Deferred income taxes		6,927		6,803
Asset retirement obligations		18,079		17,012
Operating lease liability		79		125
Total liabilities		83,076		36,223
Commitments and contingencies (Note 10)
Stockholders' equity
Common stock; par value $0.001; 100,000,000 shares authorized: issued and
outstanding 33,359,854 and 33,247,523 shares as of March 31, 2024
and June 30, 2023, respectively		33		33
Additional paid-in capital		40,652		40,098
Retained earnings		42,771		51,963
Total stockholders' equity		83,456		92,094
Total liabilities and stockholders' equity	$	166,532	$	128,317

See accompanying notes to unaudited condensed consolidated financial statements.

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EVOLUTION PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)


	Three Months Ended				Nine Months Ended
	March 31,				March 31,
	2024		2023		2024		2023
Revenues
Crude oil	$	14,538	$	11,799	$	38,913	$	40,062
Natural gas		5,860		21,598		17,943		58,816
Natural gas liquids		2,627		3,470		7,794		11,462
Total revenues		23,025		36,867		64,650		110,340
Operating costs
Lease operating costs		12,624		13,570		36,865		47,727
Depletion, depreciation, and accretion		5,900		3,383		14,760		10,439
General and administrative expenses		2,417		2,267		7,522		7,320
Total operating costs		20,941		19,220		59,147		65,486
Income (loss) from operations		2,084		17,647		5,503		44,854
Other income (expense)
Net gain (loss) on derivative contracts		(1,183)		270		(1,183)		513
Interest and other income		63		13		283		26
Interest expense		(518)		(32)		(584)		(404)
Income (loss) before income taxes		446		17,898		4,019		44,989
Income tax (expense) benefit		(157)		(3,941)		(1,174)		(9,938)
Net income (loss)	$	289	$	13,957	$	2,845	$	35,051
Net income (loss) per common share:
Basic	$	0.01	$	0.42	$	0.09	$	1.04
Diluted	$	0.01	$	0.41	$	0.08	$	1.04
Weighted average number of common shares outstanding:
Basic		32,702		33,013		32,692		33,108
Diluted		32,854		33,156		32,920		33,291

See accompanying notes to unaudited condensed consolidated financial statements.

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EVOLUTION PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)


	Nine Months Ended March 31,
	2024		2023
Cash flows from operating activities:
Net income (loss)	$	2,845	$	35,051
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and accretion		14,760		10,439
Stock-based compensation		1,585		1,155
Settlement of asset retirement obligations		(19)		(119)
Deferred income taxes		124		(100)
Unrealized (gain) loss on derivative contracts		1,063		(1,994)
Accrued settlements on derivative contracts		94		(1,130)
Other		—		(3)
Changes in operating assets and liabilities:
Receivables from crude oil, natural gas, and natural gas liquids revenues		(4,734)		16,483
Prepaid expenses and other current assets		(1,425)		(980)
Accounts payable and accrued liabilities		814		(8,146)
State and federal income taxes payable		(365)		1,063
Net cash provided by operating activities		14,742		51,719
Cash flows from investing activities:
Acquisition of oil and natural gas properties		(43,788)		(31)
Capital expenditures for oil and natural gas properties		(8,353)		(4,234)
Net cash used in investing activities		(52,141)		(4,265)
Cash flows from financing activities:
Common stock dividends paid		(12,037)		(12,114)
Common stock repurchases, including stock surrendered for tax withholding		(1,031)		(3,983)
Borrowings under senior secured credit facility		42,500		—
Repayments of senior secured credit facility		—		(21,250)
Net cash (used in) provided by financing activities		29,432		(37,347)
Net increase (decrease) in cash and cash equivalents		(7,967)		10,107
Cash and cash equivalents, beginning of period		11,034		8,280
Cash and cash equivalents, end of period	$	3,067	$	18,387

Supplemental disclosures of cash flow information:
Non-cash investing and financing transactions:
Increase (decrease) in accrued capital expenditures for oil and natural gas properties	$	2,193	$	(141)
Oil and natural gas property costs attributable to the recognition of asset retirement obligations		90		—

See accompanying notes to unaudited condensed consolidated financial statements.

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EVOLUTION PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (Unaudited)

(In thousands)


				Additional						Total
	Common Stock			Paid-in		Retained		Treasury		Stockholders'
	Shares	Par Value		Capital		Earnings		Stock		Equity
For the Three Months Ended March 31, 2024
Balances at December 31, 2023	33,507	$	34	$	40,920	$	46,485	$	—	$	87,439
Issuance of restricted common stock	5		—		—		—		—		—
Common stock repurchases, including stock surrendered for tax withholding	—		—		—		—		(818)		(818)
Retirements of treasury stock	(152)		(1)		(817)		—		818		—
Stock-based compensation	—		—		549		—		—		549
Net income (loss)	—		—		—		289		—		289
Common stock dividends paid	—		—		—		(4,003)		—		(4,003)
Balances at March 31, 2024	33,360	$	33	$	40,652	$	42,771	$	—	$	83,456

For the Nine Months Ended March 31, 2024
Balances at June 30, 2023	33,248	$	33	$	40,098	$	51,963	$	—	$	92,094
Issuance of restricted common stock	293		1		(1)		—		—		—
Common stock repurchases, including stock surrendered for tax withholding	—		—		—		—		(1,031)		(1,031)
Retirements of treasury stock	(181)		(1)		(1,030)		—		1,031		—
Stock-based compensation	—		—		1,585		—		—		1,585
Net income (loss)	—		—		—		2,845		—		2,845
Common stock dividends paid	—		—		—		(12,037)		—		(12,037)
Balances at March 31, 2024	33,360	$	33	$	40,652	$	42,771	$	—	$	83,456

For the Three Months Ended March 31, 2023
Balances at December 31, 2022	33,808	$	34	$	43,243	$	45,861	$	—	$	89,138
Issuance of restricted common stock	101		—		—		—		—		—
Common stock repurchases, including stock surrendered for tax withholding	—		—		—		—		(3,896)		(3,896)
Retirements of treasury stock	(638)		(1)		(3,895)		—		3,896		—
Stock-based compensation	—		—		453		—		—		453
Net income (loss)	—		—		—		13,957		—		13,957
Common stock dividends paid	—		—		—		(4,029)		—		(4,029)
Balances at March 31, 2023	33,271	$	33	$	39,801	$	55,789	$	—	$	95,623

For the Nine Months Ended March 31, 2023
Balances at June 30, 2022	33,471	$	33	$	42,629	$	32,852	$	—	$	75,514
Issuance of restricted common stock	476		1		(1)		—		—		—
Forfeitures of restricted stock	(26)		—		—		—		—		—
Common stock repurchases, including stock surrendered for tax withholding	—		—		—		—		(3,983)		(3,983)
Retirements of treasury stock	(650)		(1)		(3,982)		—		3,983		—
Stock-based compensation	—		—		1,155		—		—		1,155
Net income (loss)	—		—		—		35,051		—		35,051
Common stock dividends paid	—		—		—		(12,114)		—		(12,114)
Balances at March 31, 2023	33,271	$	33	$	39,801	$	55,789	$	—	$	95,623

See accompanying notes to unaudited condensed consolidated financial statements.

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Financial Statement Presentation

Nature of Operations. Evolution Petroleum Corporation (“Evolution,” and together with its consolidated subsidiaries, the “Company”) is an independent energy company focused on maximizing returns to shareholders through the ownership of and investment in onshore oil and natural gas properties in the United States. The Company’s long-term goal is to maximize total shareholder return from a diversified portfolio of long-life oil and natural gas properties built through acquisitions and through selective development opportunities, production enhancement, and other exploitation efforts on its oil and natural gas properties.

The Company’s oil and natural gas properties consist of non-operated interests in the following areas: the SCOOP and STACK plays of the Anadarko Basin located in central Oklahoma; the Chaveroo oilfield in Chaves and Roosevelt Counties of New Mexico; the Jonah Field in Sublette County, Wyoming; the Williston Basin in North Dakota; the Barnett Shale located in North Texas; the Hamilton Dome Field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir; the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana, a CO₂ enhanced oil recovery project; as well as small overriding royalty interests in four onshore Texas wells.

Interim Financial Statements. The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) for interim financial information and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. All adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods presented have been included. The interim financial information and notes hereto should be read in conjunction with the Company’s 2023 Annual Report on Form 10-K for the fiscal year ended June 30, 2023, as filed with the SEC on September 13, 2023. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year. The Company has evaluated events and transactions through the date of issuance of these unaudited condensed consolidated financial statements.

Principles of Consolidation and Reporting. The unaudited condensed consolidated financial statements include the accounts of Evolution Petroleum Corporation and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The unaudited condensed consolidated financial statements for the previous year may be condensed or include certain reclassifications to conform to the current presentation. To conform with the current year presentation, $0.6 million of accrued ad valorem and production taxes at June 30, 2023 are included with “Accrued taxes other than federal and state income tax” instead of “Accrued payables” as disclosed in Note 13, “Additional Financial Statement Information.” This reclassification has no impact on the previously reported unaudited condensed consolidated balance sheets, net income or stockholders’ equity.

Risk and Uncertainties. The Company’s oil and natural gas interests are operated by third-party operators and involve other third-party working interest owners. As a result, the Company has limited ability to influence the operation or future development of such properties. However, the Company is proactive with its third-party operators to review capital projects and related spending and present alternative plans as appropriate.

Oil and Natural Gas Properties. The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. This includes any internal costs that are directly related to property acquisition, exploration, and development activities but does not include any costs related to production, general corporate overhead, or similar activities. Oil and natural gas properties include costs that are excluded from depletion and amortization, which represent investments in unproved and unevaluated properties and include non-

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

producing leasehold, geologic and geophysical costs associated with leasehold or drilling interests, and exploration drilling costs. These costs are excluded until the project is evaluated and proved reserves are established or impairment is determined.

Use of Estimates. The preparation of the Company’s unaudited condensed consolidated financial statements in conformity with GAAP requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Significant estimates include (a) reserve quantities and estimated future cash flows associated with proved reserves, which may significantly impact depletion expense and potential impairments of oil and natural gas properties, (b) asset retirement obligations, (c) stock-based compensation, (d) fair values of derivative contract assets and liabilities, (e) income taxes and the valuation of deferred income tax assets, (f) commitments and contingencies, and (g) accruals of crude oil, natural gas, and NGL revenues and expenses. The Company analyzes estimates and judgments based on historical experience and various other assumptions and information that are believed to be reasonable. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as additional information is obtained, as new events occur, and as the Company’s environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s unaudited condensed consolidated financial statements.

Recently Issued Accounting Pronouncements

In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures (“ASU 2023-09”). ASU 2023-09 enhances the transparency of income tax disclosures by expanding the income tax rate reconciliation disclosure and income taxes paid information. ASU 2023-09 also includes certain other amendments to improve the effectiveness of income tax disclosures. ASU 2023-09 is effective for annual periods beginning after December 15, 2024. The Company is currently evaluating ASU 2023-09 and the impact it may have to the Company’s financial position, results of operations, cash flow or disclosures.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (“ASU 2016-13”). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires the use of a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. Early adoption is permitted and entities must adopt the amendment using a modified retrospective approach to the first reporting period in which the guidance is effective. For smaller reporting companies, as provided by ASU 2019-10, Financial Instruments - Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842), ASU 2016-13 is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2022. The Company adopted ASU 2016-13 effective July 1, 2023. The adoption did not have a material effect on the Company’s financial position, results of operations, cash flows or disclosures.

Other accounting pronouncements that have recently been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations, cash flows or disclosures.

Note 2. Revenue Recognition

The Company’s revenues are primarily generated from its crude oil, natural gas and NGL production from the SCOOP and STACK plays in central Oklahoma, the Chaveroo oilfield in Chaves and Roosevelt Counties of New Mexico, the Jonah Field in Sublette County, Wyoming, the Williston Basin in North Dakota, the Barnett Shale located in North Texas, the Hamilton Dome Field in Wyoming, and the Delhi Field in Northeast Louisiana. Additionally, an overriding royalty interest retained in a past divestiture of Texas properties provides de minimis revenue. The following table

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

disaggregates the Company’s revenues by major product for the three and nine months ended March 31, 2024 and 2023 (in thousands):


	Three Months Ended				Nine Months Ended
	March 31,				March 31,
	2024		2023		2024		2023
Revenues
Crude oil	$	14,538	$	11,799	$	38,913	$	40,062
Natural gas		5,860		21,598		17,943		58,816
Natural gas liquids		2,627		3,470		7,794		11,462
Total revenues	$	23,025	$	36,867	$	64,650	$	110,340

In the Jonah Field, the Company has elected to take its natural gas and NGL working interest production in-kind and markets its NGL production to Enterprise Products Partners L.P. and its natural gas production to different purchasers.

The Company does not take production in-kind at any of its other properties and does not negotiate contracts with customers for such production. The Company recognizes crude oil, natural gas, and NGL production revenue at the point in time when custody and title (“control”) of the product transfers to the customer. The sales of oil and natural gas are made under contracts which the Company’s third-party operators of its wells have negotiated with customers, which typically include variable consideration that is based on pricing tied to local indices and volumes delivered in the current month. The Company typically receives payment from the sale of oil and natural gas production one to two months after delivery.

Judgments made in applying the guidance in ASC 606, Revenue from Contracts with Customers, relate primarily to determining the point in time when control of product transfers to the customer. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained.

The Company’s contractual performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied upon control of produced hydrocarbons transferring to a customer at a specified delivery point. Consideration is allocated to completed performance obligations at the end of an accounting period.

Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received by field operators one to two months before the Company receives payment and documentation from the operator, which is typical in the oil and natural gas industry. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for the sale of the product. To estimate accounts receivable from operators’ contracts with customers, the Company uses knowledge of its properties, information from field operators, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors. Because the contractual performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, the Company recognized amounts due from contracts with field operators as “Receivables from crude oil, natural gas, and natural gas liquids revenues” on the unaudited condensed consolidated balance sheets. Differences between estimates and actual amounts received for product sales are recorded in the month that payments received from purchasers are remitted to the Company by field operators.

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Note 3. Acquisitions

SCOOP/STACK Acquisitions

On February 12, 2024, the Company closed the acquisitions of certain non-operated oil and natural gas assets in the SCOOP and STACK plays in central Oklahoma (the "SCOOP/STACK Acquisitions") from Red Sky Resources III, LLC, Red Sky Resources IV, LLC, and Coriolis Energy Partners I, LLC. After taking into account preliminary customary closing adjustments and an effective date of November 1, 2023, total combined cash consideration for the SCOOP/STACK Acquisitions was approximately $40.5 million, which includes $43.8 million paid at closing less interim purchase price adjustments totaling approximately $3.3 million related to net cash flows received on the properties subsequent to closing. The Company expects to receive the remaining net cash flows from the properties between the effective date of November 1, 2023 and the closing date, at the final post-closing settlement expected to occur during the fourth quarter of fiscal 2024. The Company accounted for these transactions as asset acquisitions and allocated all of the combined purchase price (including $0.2 million of transaction costs) to proved oil and natural gas properties. In addition, the Company recognized $0.1 million in non-cash asset retirement obligations, the estimated net present value of future net retirement costs. The transactions were funded with cash on hand and $42.5 million in borrowings under the Company’s Senior Secured Credit Facility.

The acquired assets consist of an average net working interest of approximately 3%, in 247 producing wells in the SCOOP and STACK plays of the Anadarko Basin in Oklahoma. The acquisitions also include approximately 3,700 net acres with more than 275 associated potential drilling opportunities.

Chaveroo Oilfield Participation Agreement

On September 12, 2023, the Company entered into a Participation Agreement with PEDEVCO for the joint development of a portion of PEDEVCO’s Permian Basin property in the Chaveroo oilfield, located in Chaves and Roosevelt Counties, New Mexico. The Participation Agreement does not include any of PEDEVCO’s existing vertical or horizontal wells.

Upon signing the Participation Agreement, the Company paid total cash consideration of $0.4 million, which includes less than $0.1 million of capitalized transactions costs, in exchange for a 50% working interest share in the existing leases associated with two initial development blocks. As of March 31, 2024, the Company has participated in the drilling and completion of the first development block, consisting of three gross wells (1.5 net wells). Following the completion of the second development block, the Company will have the right, but not the obligation, to elect to participate and acquire a 50% working interest share in additional development blocks at a fixed price of $450 per net acre for up to a total of approximately 16,000 gross acres.

Note 4. Property and Equipment

Property and equipment as of March 31, 2024 and June 30, 2023 consisted of the following (in thousands):


	March 31, 2024		June 30, 2023
Oil and natural gas properties
Property costs subject to amortization	$	247,106	$	197,049
Less: Accumulated depletion, depreciation, and impairment		(104,949)		(91,268)
Oil and natural gas properties, net	$	142,157	$	105,781

The Company uses the full cost method of accounting for its investments in oil and natural gas properties. All costs of acquisition, exploration, and development of oil and natural gas reserves are capitalized as the cost of oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated

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depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs would be charged to expense as a write-down of oil and natural gas properties.

Additionally, the Company assesses all properties classified as unevaluated property on a quarterly basis for possible impairment. The Company assesses properties on an individual basis or as a group, if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the full cost ceiling test limitation.

Depletion of oil and natural gas properties was $13.7 million and $9.6 million for the nine months ended March 31, 2024 and 2023, respectively. During the nine months ended March 31, 2024 and 2023, the Company incurred development capital expenditures of $9.4 million and $4.4 million, respectively.

At March 31, 2024, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month average for the 12-months ended March 31, 2024 of the West Texas Intermediate (“WTI”) crude oil spot price of $77.64 per barrel and Henry Hub natural gas spot price of $2.44 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $29.88, which was based on historical differentials to WTI as NGLs do not have any single comparable reference index price. Using these prices, at March 31, 2024 the cost center ceiling was higher than the capitalized costs of oil and natural gas properties and, as a result, no write-down was applicable.

At March 31, 2023, the ceiling test value of the Company’s reserves was calculated based on the first-day-of the month average for the 12-months ended March 31, 2023 of the WTI crude oil spot price of $91.38 per barrel and Henry Hub natural gas spot price of $5.97 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $47.07, which was based on historical prices received as NGLs do not have any single comparable reference index price. Using these prices, at March 31, 2023 the cost center ceiling was higher than the capitalized costs of oil and natural gas properties and, as a result, no write-down was applicable.

Note 5. Senior Secured Credit Facility

On April 11, 2016, the Company entered into a three-year, senior secured reserve-based credit facility, as amended, (the “Senior Secured Credit Facility”) with MidFirst Bank in an amount up to $50.0 million with a current borrowing base of $50.0 million. On May 5, 2023, the Company entered into the Tenth Amendment to the Senior Secured Credit Facility extending the maturity to April 9, 2026. The Tenth Amendment also replaced the London Interbank Offered Rate ("LIBOR") with the Secured Overnight Financing Rate (“SOFR”) plus a credit spread adjustment of 0.05% to effectively convert SOFR to a LIBOR equivalent and modifies the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, to $95.0 million. The borrowing base will be redetermined semiannually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company’s oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. The Senior Secured Credit Facility carries a commitment fee of 0.25% per annum on the undrawn portion of the borrowing base. Any borrowings under the Senior Secured Credit Facility will bear interest, at the Company’s option, at either SOFR plus 2.80%, which includes a 0.05% credit spread adjustment from LIBOR, subject to a minimum SOFR of 0.50%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%.

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The Company may elect, at its option, to prepay any borrowings outstanding under the Senior Secured Credit Facility without premium or penalty. Amounts outstanding under the Senior Secured Credit Facility are guaranteed by the Company’s direct and indirect subsidiaries and secured by a security interest in substantially all of the properties of the Company and its subsidiaries. Borrowings under the Senior Secured Credit Facility may be used for the acquisition and development of oil and natural gas properties, investments in cash flow generating properties complimentary to the production of oil and natural gas, and for letters of credit or other general corporate purposes.

The Senior Secured Credit Facility contains certain events of default, including non-payment; breaches or representation and warranties; non-compliance with covenants; cross-defaults to material indebtedness; voluntary or involuntary bankruptcy; judgments and change in control. The Senior Secured Credit Facility also contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (i) a maximum total leverage ratio of not more than 3.00 to 1.00, (ii) a current ratio of not less than 1.00 to 1.00, and (iii) a consolidated tangible net worth of not less than $40.0 million, each as defined in the Senior Secured Credit Facility. As of March 31, 2024, the Company had $42.5 million borrowings outstanding under its Senior Secured Credit Facility, resulting in $7.5 million of available borrowing capacity. For the nine months ended March 31, 2024 and 2023, the weighted average interest on borrowings under the Senior Secured Credit Facility was 8.13% and 5.25%, respectively. As of March 31, 2024, the Company is in compliance with the financial covenants under the Senior Secured Credit Facility.

On February 12, 2024, the Company entered into an amendment to the Senior Secured Credit Facility. This amendment required that the Company enter into hedges for the next 12-month period, and on a rolling 12-month basis thereafter, covering expected crude oil and natural gas production from proved developed reserves, calculated separately, equal to a minimum of 40% of expected crude oil production each month, or 25% of expected crude oil and natural gas production each month over that period. The Company has the option to choose whether to hedge 40% of expected crude oil production or 25% of expected crude oil and natural gas production.

On February 7, 2022, the Company entered into the Ninth Amendment to the Senior Secured Credit Facility. This amendment, among other things, modified the definition of utilization percentage related to the required hedging covenant such that for the purposes of determining the amount of future production to hedge, the utilization of the Senior Secured Credit Facility will be based on the Margined Collateral Value, as defined in the agreement, to the extent it exceeds the borrowing base then in effect. This amendment also required the Company to enter into hedges for the next 12-month period ending February 2023, covering 25% of expected crude oil and natural gas production over that period.

On November 9, 2021, the Company entered into the Eighth Amendment to the Senior Secured Credit Facility. This amendment, among other things, increased the borrowing base to $50.0 million and added a hedging covenant whereby the Company must hedge a minimum of 25% to 75% of future production on a rolling 12-month basis when 25% or more of the borrowing base is utilized. The hedging covenant was amended in the subsequent amendments, as discussed above.

Note 6. Income Taxes

The Company files a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions.

There were no unrecognized tax benefits, nor any accrued interest or penalties associated with unrecognized tax benefits during the periods presented in the unaudited condensed consolidated financial statements. The Company believes that it has appropriate support for the income tax positions taken and to be taken on the Company’s tax returns and that the accruals for tax liabilities are adequate for all open years based on its assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company’s federal and state income tax

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returns are open to audit under the statute of limitations for the fiscal years ended June 30, 2020 through June 30, 2023 for federal tax purposes and for the fiscal years ended June 30, 2019 through June 30, 2023 for state tax purposes. To the extent the Company utilizes net operating losses (“NOLs”) generated in earlier years, such earlier years may also be subject to audit.

For nine months ended March 31, 2024, the Company recognized income tax expense of $1.2 million and had an effective tax rate of 29.2% compared to income tax expense of $9.9 million and an effective tax rate of 22.1% for the nine months ended March 31, 2023.

The Company’s effective tax rate will typically differ from the statutory federal rate as a result of state income taxes, primarily in the states of Louisiana, Oklahoma and North Dakota, percentage depletion in excess of basis, and other permanent differences. For both periods, the respective statutory federal tax rate was 21%.

Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.

Note 7. Derivatives

The Company is exposed to certain risks relating to its ongoing business operations, including commodity price risk and interest rate risk. In accordance with the Company’s strategy and the requirements under the Senior Secured Credit Facility (as discussed in Note 5, “Senior Secured Credit Facility”), it may hedge or may be required to hedge a varying portion of anticipated oil and natural gas production for future periods. Derivatives are carried at fair value on the unaudited condensed consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the unaudited condensed consolidated statements of operations for the period in which the change occurs. The Company’s hedge strategies and objectives may change significantly as its operational profile changes or as required under the Senior Secured Credit Facility. The Company does not enter into derivative contracts for speculative trading purposes.

It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of March 31, 2024, the Company did not post collateral under any of its derivative contracts during the periods in which contracts were open as they were secured under the Company’s Senior Secured Credit Facility.

When the Company utilizes commodity derivative contracts, it expects to enter into deferred premium puts, costless put/call collars and/or fixed-price swaps to hedge a portion of its anticipated future production. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract, and a purchased put that establishes a minimum price. Fixed-price swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for the volumes under contract. The Company has elected not to designate its open derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of the derivative contracts and all payments and receipts on settled derivative contracts in “Net gain (loss) on derivative contracts” on the unaudited condensed consolidated statements of operations.

All derivative contracts are recorded at fair market value in accordance with ASC 815, Derivatives and Hedging (“ASC 815”) and ASC 820, Fair Value Measurement (“ASC 820”) and included in the unaudited condensed consolidated balance sheets as assets or liabilities. The “Derivative contract assets” and “Derivative contract liabilities” represent the difference between the market commodity prices and the hedged prices for the remaining volumes of production hedges as of March 31, 2024 (the “mark-to-market valuation”).

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The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets as of March 31, 2024 and June 30, 2023 (in thousands):


Derivatives not designated
as hedging contracts	Balance sheet	Derivative Contract Assets				Balance sheet	Derivative Contract Liabilities
under ASC 815	location	March 31, 2024		June 30, 2023		location	March 31, 2024		June 30, 2023
Commodity contracts	Current assets - derivative contract assets	$	347	$	—	Current liabilities - derivative contract liabilities	$	1,410	$	—
Commodity contracts	Other assets - derivative contract assets		—		—	Long term liabilities - derivative contract liabilities		—		—
Total derivatives not designated as hedging contracts under ASC 815		$	347	$	—		$	1,410	$	—

The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s unaudited condensed consolidated statements of operations for the three and nine months ended March 31, 2024 and 2023 (in thousands). “Realized gain (loss) on derivative contracts” represents all receipts (payments) on derivative contracts settled during the period. “Unrealized gain (loss) on derivative contracts” represents the net change in the mark-to-market valuation of the derivative contracts.


Derivatives not designated	Location of gain (loss)	Three Months Ended				Nine Months Ended
as hedging contracts	recognized in income on	March 31,				March 31,
under ASC 815	derivative contracts	2024		2023		2024		2023
Commodity contracts:
Realized gain (loss) on derivative contracts	Other income and expenses - net gain (loss) on derivative contracts	$	(120)	$	465	$	(120)	$	(1,481)
Unrealized gain (loss) on derivative contracts	Other income and expenses - net gain (loss) on derivative contracts		(1,063)		(195)		(1,063)		1,994
Total net gain (loss) on derivative contracts		$	(1,183)	$	270	$	(1,183)	$	513

As of March 31, 2024, the Company had the following open crude oil and natural gas derivative contracts:

Weighted Average

Volumes in

Swap Price per

Floor Price per

Ceiling Price per

Period

Instrument

Commodity

MMBTU/BBL

April 2024 - June 2024

Fixed-Price Swap

Crude Oil

24,250

73.41

April 2024 - June 2024

Fixed-Price Swap

Crude Oil

14,467

73.30

April 2024 - June 2024

Put

Crude Oil

38,717

75.00

July 2024 - December 2024

Fixed-Price Swap

Crude Oil

73,558

74.20

July 2024 - December 2024

Collar

Crude Oil

73,558

70.00

77.40

January 2025 - March 2025

Collar

Crude Oil

42,566

68.00

73.77

January 2025 - February 2025

Fixed-Price Swap

Natural Gas

312,286

3.56

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Subsequent to March 31, 2024, the Company entered into the following open crude oil and natural gas derivative contracts:

Weighted Average

Volumes in

Swap Price per

Floor Price per

Ceiling Price per

Period

Instrument

Commodity

MMBTU/BBL

April 2025 - June 2025

Collar

Crude Oil

41,601

65.00

84.00

March 2025 - December 2026

Fixed-Price Swap

Natural Gas

3,170,705

3.60

The Company presents the fair value of its derivative contracts at the gross amounts in the unaudited condensed consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts as of March 31, 2024 and June 30, 2023 (in thousands):


	Derivative Contracts Assets				Derivative Contracts Liabilities
Offsetting of Derivative Assets and Liabilities	March 31, 2024		June 30, 2023		March 31, 2024		June 30, 2023
Gross amounts presented in the Consolidated Balance Sheet	$	347	$	—	$	1,410	$	—
Amounts not offset in the Consolidated Balance Sheet		(347)		—		(347)		—
Net amount	$	—	$	—	$	1,063	$	—

The Company enters into an International Swap Dealers Association Master Agreements (“ISDA”) with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

Note 8. Fair Value Measurement

Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.

The three levels are defined as follows:

Level 1—Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.

Level 2—Other inputs that are observable directly or indirectly, such as quoted prices in markets that are not active or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3—Unobservable inputs for which there are little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.

Fair Value of Derivative Instruments. The Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s unaudited condensed consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable (Level 1) market

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corroborated (Level 2), or generally unobservable (Level 3). The Company classifies fair value balances based on observability of those inputs.


	March 31, 2024
	Level 1		Level 2		Level 3		Total
Assets
Derivative contract assets	$	—	$	347	$	—	$	347

Liabilities
Derivative contract liabilities	$	—	$	1,410	$	—	$	1,410

Derivative contracts listed above as Level 2 include fixed-price swaps and costless put/call collars that are carried at fair value. The Company records the net change in fair value of these positions in “Net gain (loss) on derivative contracts” in the Company’s unaudited condensed consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 7, “Derivatives,” for additional discussion of derivatives.

The Company’s derivative contracts are with large utilities with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company was exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts; however, the Company does not expect such nonperformance.

As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgement, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any period presented in this report.

Other Fair Value Measurements. The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable, and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s Senior Secured Credit Facility approximates carrying value because the interest rates approximate current market rates.

The Company follows the provisions of ASC 820, for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company’s initial measurement and any subsequent revision of asset retirement obligations (“ARO”) for which fair value is calculated using discounted future cash flows derived from historical costs and management’s expectations of future cost environments. Significant Level 3 inputs used in the calculation of ARO include the costs of plugging and abandoning wells, surface restoration, and reserve lives. Subsequent to initial recognition, revisions to estimated asset retirement obligations are made when changes occur for input values. See Note 9, “Asset Retirement Obligations,” for a reconciliation of the beginning and ending balances of the liability for the Company’s ARO.

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Note 9. Asset Retirement Obligations

The Company’s ARO represents the estimated present value of the amount expected to be incurred to plug, abandon, and remediate its oil and natural gas properties at the end of their productive lives in accordance with applicable laws and regulations. The Company records the ARO liability on the unaudited condensed consolidated balance sheets and capitalizes the cost in “Oil and natural gas properties, subject to amortization, net” during the period in which the obligation is incurred. The Company records the accretion of its ARO liabilities in “Depletion, depreciation and accretion” expense in the unaudited condensed consolidated statements of operations.

The following is a reconciliation of the activity related to the Company’s ARO liability (inclusive of the current portion) for the period ended March 31, 2024 (in thousands):


	March 31, 2024
Asset retirement obligations — beginning of period	$	17,067
Liabilities acquired⁽¹⁾		90
Accretion of discount		1,080
Asset retirement obligations — end of period		18,237
Less: current asset retirement obligations		(158)
Long-term portion of asset retirement obligations	$	18,079

(1)	See Note 3, “Acquisitions,” for additional information on the Company’s acquisition activities.

Note 10. Commitments and Contingencies

The Company is subject to various claims and contingencies in the normal course of business. In addition, from time to time, the Company receives communications from government or regulatory agencies concerning investigations or allegations of noncompliance with laws or regulations in jurisdictions in which the Company operates. The Company discloses such matters if it believes there is a reasonable possibility that a future event or events will confirm a material loss through impairment of an asset or the incurrence of a material liability. The Company accrues a material loss if it believes it probable that a future event or events will confirm a loss and the loss is reasonably subject to estimation. Furthermore, the Company will disclose any matter that is unasserted if it considers it probable that a claim will be asserted and there is a reasonable possibility that the outcome will be unfavorable and material in amount. The Company expenses legal defense costs as they are incurred.

Note 11. Stockholders’ Equity

Common Stock

As of March 31, 2024, the Company had 33,359,854 shares of common stock outstanding.

The Company began paying quarterly cash dividends on common stock in December 2013. As of March 31, 2024, the Company has cumulatively paid over $114.4 million in cash dividends. The Company paid dividends of $12.0 million and $12.1 million to its common stockholders during the nine months ended March 31, 2024 and 2023, respectively.

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The following table reflects the dividends paid per share within the respective three-month periods:


	Fiscal Year
	2024		2023
Third quarter ended March 31,	$	0.120	$	0.120
Second quarter ended December 31,		0.120		0.120
First quarter ended September 30,		0.120		0.120

On September 8, 2022, the Board of Directors approved a share repurchase program, under which the Company is authorized to repurchase up to $25.0 million of its common stock in the open market through December 31, 2024. The Company intends to fund repurchases from working capital and cash provided by operating activities. The Board of Directors along with the management team believe that a share repurchase program is complimentary to the existing dividend policy and is a tax efficient means to further improve shareholder return. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will depend on a variety of factors, including management’s assessment of the intrinsic value of the Company’s shares, the market price of the Company’s common stock, the Company’s capital needs and resources, general market and economic conditions, and applicable legal requirements. The value of shares authorized for repurchase by the Company’s Board of Directors does not require the Company to repurchase such shares or guarantee that such shares will be repurchased, and the program may be suspended, modified, or discontinued at any time without prior notice. As of March 31, 2024, a total of 0.8 million shares of the Company’s common stock have been repurchased under the plan at a total cost of approximately $4.6 million, including incremental direct transaction costs.

In December 2022, the Company entered into a Rule 10b5-1 plan that authorized a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan included a 30-day cooling off period that did not allow repurchases to commence until January 2023. The plan was effective until June 30, 2023 and had a maximum authorized amount of $5.0 million over that period. During the three and nine months ended March 31, 2023, 0.6 million shares of the Company’s common stock were repurchased under the plan at a total cost of approximately $3.9 million, including incremental direct transaction costs. These treasury shares were subsequently cancelled.

In November 2023, the Company entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan is effective until June 30, 2024, unless extended, renewed or terminated by the Company, and has a maximum authorized amount of $0.8 million over that period. The Company may alter the terms of the plan from time to time to the extent it determines changes are necessary to achieve the intended objectives of the repurchase program. During the three and nine months ended March 31, 2024, 0.1 million shares of the Company’s common stock were repurchased under the plan at a total cost of approximately $0.8 million, including incremental direct transaction costs. These treasury shares were subsequently cancelled.

During the nine months ended March 31, 2024 and 2023, the Company acquired treasury stock upon the ordinary course of scheduled vestings of employee stock-based awards to fund payroll tax withholding obligations. These treasury shares were subsequently cancelled. Such shares were valued at fair market value on the date of vesting.

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The following table summarizes all treasury stock purchases during the nine months ended March 31, 2024 and 2023 (in thousands, except per share amounts):


	Nine Months Ended
	March 31,
	2024		2023
Number of treasury shares acquired⁽¹⁾		181		650
Average cost per share⁽¹⁾	$	5.70	$	6.13
Total cost of treasury shares acquired	$	1,031	$	3,983

(1)

For the nine months ended March 31, 2024, includes 140,672 shares repurchased under the Company’s share repurchase program for a weighted average price of $5.33 per share. For the nine months ended March 31, 2023, includes 633,789 shares repurchased under the Company’s share repurchase program for a weighted average price of $6.07 per share.

Expected Tax Treatment of Dividends

For the fiscal year ended June 30, 2023, all common stock dividends for that fiscal year were treated for tax purposes as qualified dividend income to the recipients. Based on its current projections for the fiscal year ended June 30, 2024, the Company expects all common stock dividends for such period to be treated as qualified dividend income to the recipients. Such projections are based on the Company’s reasonable expectations as of March 31, 2024 and are subject to change based on the Company’s final tax calculations at the end of the fiscal year.

Stock-Based Incentive Plan

The Evolution Petroleum Corporation 2016 Equity Incentive Plan (as amended, the “2016 Plan”) authorizes the issuance of 3.6 million shares of common stock prior to its expiration on December 8, 2026. Incentives under the 2016 Plan may be granted to employees, directors, and consultants of the Company in any one or a combination of the following forms: incentive stock options and non-statutory stock options, stock appreciation rights, restricted stock awards and restricted stock unit awards, performance share awards, performance cash awards, and other forms of incentives valued in whole or in part by reference to, or otherwise based on, the Company’s common stock, including its appreciation in value. As of March 31, 2024 and June 30, 2023, approximately 0.9 million shares and 1.3 million shares, respectively, remained available for grant under the 2016 Plan.

The Company estimates the fair value of stock-based compensation awards on the grant date to provide the basis for future compensation expense. During the three and nine months ended March 31, 2024, the Company recognized $0.5 million and $1.6 million, respectively, related to stock-based compensation. During the three and nine months ended March 31, 2023, the Company recognized $0.5 million and $1.2 million, respectively, related to stock-based compensation expense. Stock-based compensation expense is recorded as a component of “General and administrative expenses” on the unaudited condensed consolidated statements of operations.

Time-Vested Restricted Stock Awards

Time-vested restricted stock awards contain service-based vesting conditions and expire after a maximum of four years from the date of grant if unvested. The common shares underlying these awards are issued on the date of grant and participate in dividends paid by the Company. These service-based awards vest with continuous employment by the Company, generally in annual installments over terms of three to four years. Awards to the Company’s directors generally have one-year cliff vesting. For such awards, grant date fair value is based on market value of the Company’s common stock at the time of grant. This value is then amortized ratably over the service period. Previously recognized amortization expense subsequent to the last vesting date of an award is reversed in the event that the holder has no longer rendered service to the Company resulting in forfeiture of the award.

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Performance-Based Restricted Stock Awards and Performance-Based Contingent Stock Units

Performance-based restricted stock awards and performance-based contingent stock units contain market-based vesting conditions based on the price of the Company’s common stock, the intrinsic value indexed solely to its common stock or the intrinsic value indexed to its common stock compared to the performance of the common stock of its peers. The common shares underlying the Company’s performance-based restricted stock awards are issued on the date of grant and participate in dividends paid by the Company and expire after a maximum of four years from the date of grant if unvested. Performance-based contingent share units do not participate in dividends and shares are only issued in part or in full upon the attainment of vesting conditions, generally have a lower probability of achievement and expire after a maximum of four years from the date of grant if unvested. Shares underlying performance-based contingent share units are reserved from the 2016 Plan. Performance-based restricted stock awards and contingent restricted stock units are valued using a Monte Carlo simulation and geometric Brownian motion techniques applied to the historical volatility of the Company’s total stock return compared to the historical volatilities of other companies or indices to which the Company compares its performance and/or the Company’s absolute total stock return. For certain awards, this Monte Carlo simulation also provides an expected vesting term. Stock-based compensation is recognized ratably over the expected vesting period, so long as the award holder remains an employee of the Company. Previously recognized compensation expense is only reversed for the awards with market-based vesting conditions if the requisite service period is not rendered by the holder resulting in forfeiture of the award or as a result of regulatory required clawback.

Vesting of grants with performance-based vesting conditions is dependent on the future price of the Company’s common stock. Such awards vest in part or in full if the trailing total returns on the Company’s common stock for a specified three-year period exceed the corresponding total returns of various quartiles of indices consisting of peer companies or, in some cases, vest when the average of the Company’s closing common stock price over a defined measurement period meets or exceeds a required common stock price.

During the nine months ended March 31, 2024, the Company granted a total of 0.4 million equity awards that included 0.2 million time-vested restricted stock awards, 0.1 million performance-based restricted stock awards, and 0.1 million performance-based contingent stock units.

During the nine months ended March 31, 2023, the Company granted a total of 0.5 million equity awards that included 0.4 million time-vested restricted stock awards, 0.1 million performance-based restricted stock awards, and less than 0.05 million of performance-based contingent stock units.

For performance-based awards granted during the nine months ended March 31, 2024 and 2023, the assumptions used in the Monte Carlo simulation valuations were as follows:


	Nine Months Ended
	March 31,
	2024		2023
Weighted average fair value of performance-based awards granted	$	3.58	$	6.52
Risk-free interest rate		4.87%		3.91% to 4.51%
Expected term in years		2.77		2.36 to 2.78
Expected volatility		55.0%		56.5% to 70.9%
Dividend yield		7.4%		6.1% to 7.8%

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unvested restricted stock awards as of March 31, 2024 consisted of the following:


		Weighted
	Number of	Average
	Restricted	Grant-Date
Award Type	Shares	Fair Value
Time-vested awards	407,103	$	6.59
Performance-based awards	278,688		5.46
Unvested at March 31, 2024	685,791	$	6.13

The following table sets forth the restricted stock award transactions for the nine months ended March 31, 2024:


						Weighted
		Weighted		Unamortized		Average
	Number of	Average		Compensation		Remaining
	Restricted	Grant-Date		Expense		Amortization
	Shares	Fair Value		(In thousands)		Period (Years)
Unvested at June 30, 2023	595,414		6.48	$	2,827	2.4
Time-vested shares granted	157,192		6.22
Performance-based shares granted	136,315		4.80
Vested	(203,130)		6.33
Unvested at March 31, 2024	685,791	$	6.13	$	2,995	1.9

The following table sets forth contingent restricted stock unit transactions for the nine months ended March 31, 2024:


						Weighted
				Unamortized		Average
	Number of	Weighted Average		Compensation		Remaining
	Restricted	Grant-Date		Expense		Amortization
	Stock Units	Fair Value		(In thousands)		Period (Years)
Unvested at June 30, 2023	96,398	$	3.49	$	195	1.9
Performance-based awards granted	102,239		1.95
Unvested at March 31, 2024	198,637	$	2.70	$	275	1.8

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 12. Earnings (Loss) per Common Share

The following table sets forth the computation of basic and diluted earnings (loss) per common share, reflecting the application of the two-class method (in thousands, except per share amounts):


	Three Months Ended				Nine Months Ended
	March 31,				March 31,
	2024		2023		2024		2023
Numerator
Net income (loss)	$	289	$	13,957	$	2,845	$	35,051
Undistributed earnings allocated to unvested restricted stock		(6)		(253)		(58)		(515)
Net income (loss) for earnings per share calculation	$	283	$	13,704	$	2,787	$	34,536

Denominator
Weighted average number of common shares outstanding — Basic		32,702		33,013		32,692		33,108
Effect of dilutive securities:
Unvested restricted stock awards		124		143		192		178
Unvested contingent restricted stock units		28		—		36		5
Weighted average number of common shares and dilutive potential common shares used in diluted earnings per share		32,854		33,156		32,920		33,291

Net income (loss) per common share — Basic	$	0.01	$	0.42	$	0.09	$	1.04
Net income (loss) per common share — Diluted	$	0.01	$	0.41	$	0.08	$	1.04

Unvested restricted stock awards (both time-vested and performance-based), totaling approximately 0.1 million for each of the three and nine months ended March 31, 2024 were not included in the computation of diluted earnings per common share because the effect would have been anti-dilutive.

Unvested restricted stock awards (both time-vested and performance-based), totaling approximately 0.3 million and 0.1 million for the three and nine months ended March 31, 2023, respectively, were not included in the computation of diluted earnings per common share because the effect would have been anti-dilutive.

In addition, unvested performance-based restricted stock awards and unvested contingent restricted stock units that would not meet the performance criteria as of the period end are excluded from the computation of diluted earnings per common share.

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 13. Additional Financial Statement Information

Certain amounts on the unaudited condensed consolidated balance sheets are comprised of the following (in thousands):


	March 31, 2024		June 30, 2023
Prepaid expenses and other current assets:
Other receivables⁽¹⁾	$	2,576	$	18
Prepaid insurance		311		727
Prepaid federal and state income taxes		1,980		805
Carryback of EOR tax credit		347		347
Advances to operators		594		—
Prepaid other		467		380
Total prepaid expenses and other current assets	$	6,275	$	2,277

Other assets:
Deposit	$	1,158	$	1,158
Right of use asset under operating lease		160		183
Total other assets	$	1,318	$	1,341

Accrued liabilities and other:
Accrued payables	$	2,789	$	3,005
Accrued capital expenditures		—		167
Accrued incentive and other compensation		902		941
Accrued royalties payable		625		977
Accrued taxes other than federal and state income tax		1,166		739
Accrued severance		—		81
Accrued settlements on derivative contracts		94		—
Operating lease liability		97		59
Asset retirement obligations due within one year		158		55
Accrued - other		154		3
Total accrued liabilities and other	$	5,985	$	6,027

(1)	At March 31, 2024, includes $2.6 million receivable related to customary purchase price adjustments related to the SCOOP/STACK Acquisitions. See Note 3, “Acquisitions” for a further discussion.

Note 14. Subsequent Events

Dividend Declaration

On May 6, 2024, the Company declared a quarterly cash dividend of $0.120 per share of common stock to shareholders of record on June 14, 2024 and payable on June 28, 2024.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Executive Overview

Liquidity and Capital Resources

Results of Operations

Critical Accounting Policies

Commonly Used Terms

“Current quarter” refers to the three months ended March 31, 2024, our third quarter of fiscal year 2024.

“Year-ago quarter” refers to the three months ended March 31, 2023, our third quarter of fiscal year 2023.

Executive Overview

General

Evolution Petroleum Corporation is an independent energy company focused on maximizing total returns to its shareholders through the ownership of and investment in onshore oil and natural gas properties in the United States. In support of that objective, our long-term goal is to maximize total shareholder return from a diversified portfolio of long-life oil and natural gas properties built through acquisitions and through selective development opportunities, production enhancements, and other exploitation efforts on our oil and natural gas properties.

Our oil and natural gas properties consist of non-operated interests in the following areas: the SCOOP and STACK plays of the Anadarko Basin located in central Oklahoma; the Chaveroo oilfield in Chaves and Roosevelt Counties of New Mexico; the Jonah Field in Sublette County, Wyoming; the Williston Basin in North Dakota; the Barnett Shale located in North Texas; the Hamilton Dome Field located in Hot Springs County, Wyoming; the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana; as well as small overriding royalty interests in four onshore central Texas wells.

Our non-operated interests in the SCOOP and STACK plays, an oil and natural gas producing property in the Anadarko basin, consist of approximately 3% average net working interest and approximately 2% average net revenue interests located on approximately 3,700 net acres across Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties in Oklahoma. The oil and natural gas properties are primarily operated by Continental Resources, Inc., Ovintiv USA Inc. and EOG Resources, Inc. with approximately 40% of wells operated by other operators.

Our non-operated interests in the Chaveroo oilfield consist of a 50% net working interest, with an associated 41% revenue interest, in approximately 1,625 gross acres associated with ten development locations with the right to acquire the same working interest in additional development locations and associated acreage at a fixed price. The field is operated by PEDEVCO Corp. (“PEDEVCO”). See “Chaveroo Oilfield Participation Agreement” below for further information.

Our non-operated interests in the Jonah Field, a natural gas and NGL producing field in Sublette County, Wyoming, consist of approximately 20% average net working interest and approximately 15% average net revenue interest located on approximately 950 net acres. The properties are operated by Jonah Energy, an established operator in the geographic region.

Our non-operated interests in the Williston Basin, an oil and natural gas producing property, consist of approximately 39% average net working interest and approximately 33% average net revenue interest located on approximately 43,300 net acres (approximately 92% held by production) across Billings, Golden Valley, and McKenzie Counties in North

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Dakota. The properties are operated by Foundation Energy Management, an established operator in the geographic region.

Our non-operated interests in the Barnett Shale, a natural gas and NGL producing shale reservoir, consist of approximately 17% average net working interest and approximately 14% average net revenue interest (inclusive of small overriding royalty interests). The approximately 21,000 net acres are held by production across nine North Texas counties. The oil and natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by six other operators.

Our non-operated interests in the Hamilton Dome Field, a secondary recovery field utilizing water injection wells to pressurize the reservoir, consist of approximately 24% average net working interest, with an associated 20% average net revenue interest (inclusive of a small overriding royalty interest). The approximately 5,900 gross acre unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company, who owns the majority of the remaining working interest in the Hamilton Dome Field. The Hamilton Dome Field is located in the southwest region of the Big Horn Basin in northwest Wyoming.

Our non-operated interests in the Delhi Field, a CO₂-EOR project producing oil and NGLs, consist of approximately 24% average net working interest, with an associated 19% revenue interest and separate overriding royalty and mineral interests of approximately 7% yielding a total average net revenue interest of approximately 26%. The field is operated by Denbury Onshore LLC (“Denbury”), which was acquired by Exxon Mobil Corporation during the current fiscal year. The Delhi Field is located in northeast Louisiana in Franklin, Madison, and Richland Parishes and encompasses approximately 14,000 gross unitized acres, or approximately 3,200 net acres.

Recent Developments

SCOOP/STACK Acquisitions

On February 12, 2024, we closed the acquisitions of certain non-operated oil and natural gas assets in the SCOOP and STACK plays in central Oklahoma (the "SCOOP/STACK Acquisitions") from Red Sky Resources III, LLC, Red Sky Resources IV, LLC, and Coriolis Energy Partners I, LLC. After taking into account preliminary customary closing adjustments and an effective date of November 1, 2023, total combined cash consideration for the SCOOP/STACK Acquisitions was approximately $40.5 million, which includes $43.8 million paid at closing less interim purchase price adjustments totaling approximately $3.3 million related to net cash flows earned on the properties from the effective date to the closing date. We expect to receive the remaining net cash flows from the properties between the effective date of November 1, 2023 and the closing date, at the final post-closing settlement process expected to occur during the fourth quarter of fiscal 2024.

The acquired assets consist of an average net working interest of approximately 3% in 247 producing wells in the SCOOP and STACK plays of the Anadarko Basin in Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties, Oklahoma. The acquisitions also include approximately 3,700 net acres with more than 275 associated potential drilling opportunities.

Senior Secured Credit Facility

On February 12, 2024, we entered into an amendment to the Senior Secured Credit Facility. This amendment required that we enter into hedges for the next 12-month period, and on a rolling 12-month basis thereafter, covering expected crude oil and natural gas production from proved developed reserves, calculated separately, equal to a minimum of 40% of expected crude oil production each month, or 25% of expected crude oil and natural gas production each month over that period. We have the option to choose whether to hedge 40% of expected crude oil production or 25% of expected crude oil and natural gas production.

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Appointment of Chief Accounting Officer

On December 18, 2023, we announced that the Board of Directors approved the appointment of Kelly M. Beatty as Chief Accounting Officer, effective January 1, 2024. Ms. Beatty has been serving as Principal Accounting Officer since December 2022 and has served as the Company’s Controller since February 2022.

Share Repurchase Program

In November 2023, we entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan is effective until June 30, 2024, unless extended, renewed or terminated, and has a maximum authorized amount of $0.8 million over that period. We may alter the terms of the plan from time to time to the extent we determine changes are necessary to achieve the intended objectives of our repurchase program. During the three and nine months ended March 31, 2024, 0.1 million shares of the Company’s common stock have been repurchased under the plan at a cost of approximately $0.8 million, including incremental direct transaction costs. These shares were subsequently cancelled.

Chaveroo Oilfield Participation Agreement

On September 12, 2023, we entered into a participation agreement (the “Participation Agreement”) with PEDEVCO for the joint development of the Chaveroo oilfield, a conventional oil-bearing San Andres field located in Chaves and Roosevelt Counties, New Mexico (the “Chaveroo Field”).

Pursuant to the Participation Agreement, we have the right, but not the obligation, to elect to participate in drilling locations on approximately 16,000 gross leasehold acres consisting of all leasehold rights from surface to the base of the San Andres formation, where PEDEVCO currently holds leasehold interest. We have agreed to pay PEDEVCO $450 per acre to acquire a 50% working interest share in the leases associated with the locations that we choose to participate in. We have entered into a standard operating agreement with PEDEVCO serving as the operator with respect to the development of the properties. The Participation Agreement includes customary representations and warranties of the parties and other terms and conditions that are standard in such participation agreements.

During the three months ended September 30, 2023, we paid total cash consideration of $0.4 million, which includes less than $0.1 million of capitalized transaction costs, in exchange for a 50% working interest share in 1,625 gross leasehold acres associated with two initial development blocks. As of March 31, 2024, we have participated in the drilling and completion of the first development block which consisted of three gross (1.5 net ) wells. Following the completion of the second development block, we will have the right, but not the obligation, to elect to participate in additional development blocks. The Participation Agreement initially includes up to 80 gross drilling locations across twelve development blocks. Refer to Capital Expenditures below for a further discussion of Chaveroo drilling and completion activities since entering into the Participation Agreement.

Risks and uncertainties

The global economy was deeply impacted by the effects of the novel coronavirus (“COVID-19”) pandemic and related efforts to mitigate the spread of the disease. These events led to crude oil prices falling to historic lows during the second quarter of 2020 and remaining depressed through much of 2020. Beginning in 2021, the demand for oil and natural gas recovered primarily as a result of the roll-out of the COVID-19 vaccine and lessening of pandemic related government restrictions on individuals and businesses. During the current year, natural gas prices have declined primarily due to a warmer winter, and during the current quarter, oil prices have increased somewhat due to geopolitical factors and increased demand relative to supply.

In addition, the conflict in the Middle East, the military activities of Russia into Ukraine and the subsequent sanctions imposed on Russia and other actions have created significant market uncertainties, including uncertainties around potential supply disruptions for oil and natural gas, which have further enhanced volatility in global commodity prices.

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At times, we do maintain cash balances in excess of the U.S. Federal Deposit Insurance Corporation (“FDIC”); however, we believe our bank counterparty to be financially sound. We also utilize insured cash sweep deposits to maximize the amount of our cash that is protected by FDIC insurance. We also rely heavily on our third-party operators who manage their own liquidity with various financial institutions.

The Federal Reserve has taken actions to raise interest rates in an attempt to tame inflation and slow the economy, which has contributed to volatility in markets.

Given the dynamic nature of these events, we cannot reasonably estimate the period of time that these market conditions will persist; predict the broader impact of liquidity concerns around financial institutions; the impact to long-term cost of capital or economic growth as a result of the Federal Reserve’s policies; or the impact on the commodity prices that we realize.

Currently, our oil and natural gas properties are operated by third-party operators and involve other third-party working interest owners. As a result, we have limited ability to influence the operation or future development of such properties. Despite these uncertainties, we remain focused on our long-term objectives and continue to be proactive with our third-party operators to review capital expenditures and present alternative plans as necessary.

Liquidity and Capital Resources

As of March 31, 2024, we had $3.1 million in cash and cash equivalents and $42.5 million outstanding on our Senior Secured Credit Facility compared to $11.0 million in cash and cash equivalents and no borrowings outstanding on our Senior Secured Credit Facility at June 30, 2023. Our primary sources of liquidity and capital resources during the nine months ended March 31, 2024 were cash provided by operations as well as net borrowings under our Senior Secured Credit Facility. Our primary uses of liquidity and capital resources for the nine months ended March 31, 2024 were our SCOOP/STACK Acquisitions, cash dividend payments to our common stockholders, and development capital expenditures, primarily at Chaveroo oilfield where we participated in drilling three gross (1.5 net) wells. As of March 31, 2024, working capital was $7.6 million, a decrease of $1.3 million from working capital of $8.9 million as of June 30, 2023.

The Senior Secured Credit Facility has a maximum capacity of $50.0 million subject to a borrowing base determined by the lender based on the value of our oil and natural gas properties. The Senior Secured Credit Facility has a current borrowing base of $50.0 million, with $42.5 million drawn as of March 31, 2024. The Senior Secured Credit Facility is secured by substantially all of our oil and natural gas properties and matures on April 9, 2026.

Borrowings bear interest, at our option, at either the SOFR plus 2.80% or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%. For the nine months ended March 31, 2024 and 2023, the weighted average interest on our borrowings was 8.13% and 5.25%, respectively. The Senior Secured Credit Facility contains covenants requiring the maintenance of (i) a total leverage ratio of not more than 3.00 to 1.00, (ii) a current ratio of not less than 1.00 to 1.00, and (iii) a consolidated tangible net worth of not less than $40.0 million, each as defined in the Senior Secured Credit Facility. It also contains other customary affirmative and negative covenants, including a hedging covenant discussed below, and events of default. As of March 31, 2024, we were in compliance with all covenants under the Senior Secured Credit Facility.

On May 5, 2023, we entered into the Tenth Amendment to the Senior Secured Credit Facility. This amendment, among other things, extended the maturity of our Senior Secured Credit Facility to April 9, 2026, converted our benchmark interest rate from LIBOR to SOFR plus a credit spread adjustment of 0.05%, and modified the Margined Collateral

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Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, to $95.0 million. We are required to enter into hedges on a rolling 12-month basis when the borrowings under the Senior Secured Credit Facility exceed 25% of the Margined Collateral Value. The required amount of hedged oil and natural gas production is related to the amount of borrowings outstanding. At each redetermination, our Margined Collateral Value takes into account the estimated value of our oil and natural gas properties, proved developed reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria.

On February 7, 2022, we entered into the Ninth Amendment to the Senior Secured Credit Facility. This amendment, among other things, modified the definition of utilization percentage related to the required hedging covenant such that for the purposes of determining the amount of future production to hedge, the utilization of the Senior Secured Credit Facility will be based on the Margined Collateral Value, as defined in the agreement, to the extent it exceeds the borrowing base then in effect. This amendment also required us to enter into hedges for the next 12-month period ending February 2023, covering 25% of expected crude oil and natural gas production over that period.

On November 9, 2021, we entered into the Eighth Amendment to the Senior Secured Credit Facility. This amendment, among other things, increased the borrowing base to $50.0 million and added a hedging covenant whereby we must hedge a minimum of 25% to 75% of future production on a rolling 12-month basis when 25% or more of the borrowing base is utilized. The hedging covenant was amended in the subsequent amendments, as discussed above.

We have historically funded operations through cash from operations and working capital and utilized our credit facility for property acquisitions. Our primary source of cash from operations is the sale of produced crude oil, natural gas, and NGLs. A portion of these cash flows is used to fund capital expenditures and pay cash dividends to shareholders. We expect to fund near-future capital expenditures with cash flows from operating activities and existing working capital, and as needed from borrowings under our Senior Secured Credit Facility.

We are pursuing new growth opportunities through acquisitions and other transactions. In addition to cash on hand, we have access to the undrawn portion of the borrowing base available under our Senior Secured Credit Facility, totaling $7.5 million as of March 31, 2024. We also have an effective shelf registration statement with the SEC under which we may issue up to $500.0 million of new debt or equity securities.

Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 42 consecutive quarterly dividends. Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of our financial strategy, and it is our long-term goal to increase dividends over time, as appropriate. On May 6, 2024, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on June 14, 2024 and payable on June 28, 2024.

On September 8, 2022, our Board of Directors approved a share repurchase program, under which we are authorized to repurchase up to $25.0 million of our common stock in the open market through December 31, 2024. We intend to fund any repurchases from working capital and cash provided by operating activities. As we continue to focus on our goal of maximizing total shareholder return, the Board of Directors along with the management team believe that a share repurchase program is a complimentary option to the existing dividend policy and investment opportunities, and is a tax efficient means to further improve shareholder return.

In December 2022, we entered into a Rule 10b5-1 plan that authorized a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan included a 30-day cooling off period that did not allow repurchases to commence until January 2023. The plan was effective until June 30, 2023 and had a maximum authorized amount of $5.0 million over that period. During the three and nine months ended March 31, 2023, 0.6 million shares of our common stock were repurchased under the plan at a total cost of approximately $3.9 million, including incremental direct transaction costs. These shares were subsequently cancelled.

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repurchase program. During the three and nine months ended March 31, 2024, 0.1 million shares of the Company’s common stock have been repurchased under the plan at a cost of approximately $0.8 million, including incremental direct transaction costs. These shares were subsequently cancelled.

Capital Expenditures

During the nine months ended March 31, 2024, we incurred $9.4 million in capital expenditures, a majority of which was spent at the Chaveroo Field where we participated in the drilling and completion of three gross (1.5 net) wells. First production on the three gross wells at Chaveroo Field occurred at the beginning of February 2024. During the first fiscal quarter of 2024, we also participated in the drilling and completion of two new wells in the Delhi Field. Production of the Delhi wells came online in the first fiscal quarter of 2024 and produced consistently in the second fiscal quarter.

Based on discussions with our operators, we expect capital workover projects to continue in all the fields. Overall, for fiscal year 2024, we expect budgeted capital expenditures to be in the range of $10.0 million to $12.0 million, which excludes any potential acquisitions. Our expected capital expenditures for fiscal year 2024 include the two new drilled wells at Delhi Field and three wells at Chaveroo Field, both of which are discussed above. As mentioned in Recent Developments, we closed three separate definitive agreements to purchase oil and natural gas properties in the SCOOP/STACK plays in central Oklahoma for a combined purchase price of $40.5 million after taking into account preliminary post-close adjustments. Our budgeted capital expenditures discussed above also include capital projects associated with properties acquired in the SCOOP/STACK Acquisitions.

Funding for our anticipated capital expenditures over the near-term is expected to be met from cash flows from operations and current working capital and, as needed, from borrowings under our Senior Secured Credit Facility.

Full Cost Pool Ceiling Test

Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated depletion, depreciation, and amortization and related deferred taxes, are limited to the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and natural gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average first day of the month price for our petroleum products during the 12-month period ending with the balance sheet date. The prices used in calculating our ceiling test as of March 31, 2024 were $77.64 per barrel of oil, $2.44 per MMBtu of natural gas and $29.88 per barrel of NGLs. As of March 31, 2024, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling. If commodity price levels were to substantially decline from the 12-month average first day of the month pricing levels as of March 31, 2024 and remain down for a prolonged period of time, our valuation ceiling over our capitalized costs may be reduced and adversely impact our ceiling tests in future quarters. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required in the future. Additionally, a 10% reduction in respective commodity prices at March 31, 2024, while all other factors remained constant, would not have generated an impairment.

Overview of Cash Flow Activities


	Nine Months Ended March 31,
	2024		2023		Change
Cash flows provided by operating activities	$	14,742	$	51,719	$	(36,977)
Cash flows used in investing activities		(52,141)		(4,265)		(47,876)
Cash flows provided by (used in) financing activities		29,432		(37,347)		66,779
Net increase (decrease) in cash and cash equivalents	$	(7,967)	$	10,107	$	(18,074)

Cash provided by operating activities for the nine months ended March 31, 2024 decreased $37.0 million compared to the nine months ended March 31, 2023 primarily due to a decrease in revenues. Total revenues decreased $45.7 million as compared to the prior year period primarily due to lower commodity prices coupled with lower sales volumes. Our

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average realized price per barrel of oil equivalent (“BOE”) decreased $19.71, or 35.8% from the prior year period. Refer to “Results of Operations” below for further information.

Cash used in investing activities for the nine months ended March 31, 2024 increased $47.9 million compared to the nine months ended March 31, 2023 primarily due to the acquisition of our SCOOP/STACK properties in February 2024 together with an increase in capital expenditures related to the drilling and completion of three new wells in the Chaveroo Field. As of the quarter ended March 31, 2024, we have paid approximately $43.8 million for the SCOOP/STACK Acquisitions and have accrued estimated preliminary purchase price adjustments of $3.3 million related to net cash flows earned on the properties from the effective date to the closing date to arrive a net purchase price of $40.5 million.

Net cash flows provided by financing activities for the nine months ended March 31, 2024 were $29.4 million compared to net cash flows used in financing activities of $37.3 million for the nine months ended March 31, 2023. In the current year period, we borrowed $42.5 million under our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions which was partially offset by $12.0 million cash dividends paid to our common stockholders together with $0.8 million paid to repurchase shares of common stock under our share repurchase plan. In the prior year period, we had repayments totaling $21.3 million of borrowings outstanding under our Senior Secured Credit Facility, $12.1 million in cash dividends paid to our common stockholders and $3.9 million paid to repurchase shares of common stock under our share repurchase program.

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Results of Operations

Three Months Ended March 31, 2024 and 2023

We reported net income of $0.3 million and $14.0 million for the three months ended March 31, 2024 and 2023, respectively. The following table summarizes the comparison of financial information for the periods presented:


	Three Months Ended
	March 31,
(in thousands, except per unit and per BOE amounts)	2024		2023		Variance		Variance %
Net income (loss)	$	289	$	13,957	$	(13,668)	(97.9)	%
Revenues:
Crude oil		14,538		11,799		2,739	23.2	%
Natural gas		5,860		21,598		(15,738)	(72.9)	%
Natural gas liquids		2,627		3,470		(843)	(24.3)	%
Total revenues		23,025		36,867		(13,842)	(37.5)	%
Operating costs:
Lease operating costs:
CO₂ costs		1,035		1,821		(786)	(43.2)	%
Ad valorem and production taxes		1,458		1,642		(184)	(11.2)	%
Other lease operating costs		10,131		10,107		24	0.2	%
Depletion, depreciation, and accretion:
Depletion of full cost proved oil and natural gas properties		5,532		3,098		2,434	78.6	%
Accretion of asset retirement obligations		368		285		83	29.1	%
General and administrative expenses:
General and administrative		1,868		1,814		54	3.0	%
Stock-based compensation		549		453		96	21.2	%
Other income (expense):
Net gain (loss) on derivative contracts		(1,183)		270		(1,453)	(538.1)	%
Interest and other income		63		13		50	384.6	%
Interest expense		(518)		(32)		(486)	1,518.8	%
Income tax (expense) benefit		(157)		(3,941)		3,784	(96.0)	%

Production:
Crude oil (MBBL)		199		167		32	19.2	%
Natural gas (MMCF)		2,115		2,204		(89)	(4.0)	%
Natural gas liquids (MBBL)		104		104		—	-	%
Equivalent (MBOE)⁽¹⁾		656		638		18	2.8	%
Average daily production (BOEPD)⁽¹⁾		7,209		7,089		120	1.7	%

Average price per unit⁽²⁾:
Crude oil (BBL)	$	73.06	$	70.65	$	2.41	3.4	%
Natural gas (MCF)		2.77		9.80		(7.03)	(71.7)	%
Natural Gas Liquids (BBL)		25.26		33.37		(8.11)	(24.3)	%
Equivalent (BOE)⁽¹⁾		35.10		57.79		(22.69)	(39.3)	%

Average cost per unit:
Operating costs:
Lease operating costs:
CO₂ costs	$	1.58	$	2.85		(1.27)	(44.6)	%
Ad valorem and production taxes		2.22		2.57		(0.35)	(13.6)	%
Other lease operating costs		15.44		15.84		(0.40)	(2.5)	%
Depletion of full cost proved oil and natural gas properties		8.43		4.86		3.57	73.5	%
General and administrative expenses:
General and administrative		2.85		2.84		0.01	0.4	%
Stock-based compensation		0.84		0.71		0.13	18.3	%

(1)	Equivalent oil reserves are defined as six MCF of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.

(2)	Amounts exclude the impact of cash paid or received on the settlement of derivative contracts since we did not elect to apply hedge accounting.

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Revenues

Crude oil, natural gas and NGL revenues were $23.0 million and $36.9 million for the three months ended March 31, 2024 and 2023, respectively. The decrease in revenues is primarily due to the decrease in our average realized price per BOE partially offset by an increase in our crude oil sales volumes. Our average realized commodity price (excluding the impact of derivative contracts) for the three months ended March 31, 2024 decreased approximately $22.69 per BOE, or 39.3%, compared to the prior year period. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, inventory storage levels, basis differentials and other factors. Realized natural gas prices decreased 71.7% from the prior year period, which was the largest portion of the driver of the decrease in revenues. This was partially attributed to the prior year period benefit of strong natural gas price differentials received at the Jonah Field where we realized an average natural gas price of $20.31 per MCF in the prior year period compared to $3.94 per MCF in the current year quarter. Average daily equivalent production increased 1.7% from 7,089 BOEPD in the prior year period to 7,209 BOEPD in the current period primarily due to the acquisitions of non-operated working interests in the SCOOP/STACK in the latter part of February 2024 and first production at our wells in the Chaveroo Field in early February 2024, which collectively increased current quarter production by approximately 1,020 BOEPD. These increases were partially offset by a decrease in production at our Barnett Shale properties. We began experiencing production declines and downtime in April 2023 at Barnett Shale. Production declines were primarily related to compression issues due to excessive heat, downtime in the gathering and processing system, pipeline rerouting and optimization, and our operator’s decision to temporarily shut-in certain low margin wells. As of March 31, 2024, the midstream issues have been moderated, but due to low natural gas prices the shut-in wells remain offline which has continued to negatively impact production volumes.

Lease Operating Costs

Ad valorem and production taxes were $1.5 million and $1.6 million for the three months ended March 31, 2024 and 2023, respectively. On a per unit basis, ad valorem and production taxes were $2.22 per BOE and $2.57 per BOE for the three months ended March 31, 2024 and 2023, respectively. The decrease in ad valorem and production taxes is primarily due to decreases in realized natural gas and NGLs revenues described above, as production taxes are based on sales at the wellhead.

The following table summarizes CO₂costs per Mcf and CO₂volumes for the three months ended March 31, 2024 and 2023. CO₂ purchase costs are for the Delhi Field. Under our contract with the Delhi Field operator, purchased CO₂ is priced at 1% of the realized oil price in the field per MCF, plus sales taxes and transportation costs as per contract terms.


	Three Months Ended
	March 31,
	2024		2023		Variance		Variance %
CO₂ costs per MCF	$	0.92	$	0.92	$	—	—	%
CO₂ volumes (MMCF per day, gross)		52.1		91.7		(39.6)	(43.2)	%

The $0.8 million decrease in CO₂costs for the three months ended March 31, 2024 was primarily due to a 43.2% decrease in purchased CO₂volumes, which was primarily due to the suspension of CO₂ purchases at the end of February 2024 due to maintenance on the CO₂ pipeline. CO₂ purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. We do not have any ownership in the CO₂ pipeline which is owned and operated by Denbury. On a per unit basis, CO₂ costs were $1.58 per BOE and $2.85 per BOE for the three months ended March 31, 2024 and 2023, respectively.

Other lease operating costs were primarily flat, compared to the prior year period. On a per unit basis, other lease operating costs decreased slightly to $15.44 per BOE for the three months ended March 31, 2024 from $15.84 per BOE in the year-ago quarter. The largest decrease in operating costs was at our Barnett Shale properties offset by an additional LOE incurred as a result of our SCOOP/STACK Acquisitions. At the Barnett Shale, significant cost savings efforts are being prioritized due to the lower realized natural gas prices and the shut-in of certain low margin wells at current natural gas prices. We are experiencing lower operating costs in all cost categories, especially lower water hauling costs and lower gathering, transportation and processing charges.

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Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased $2.4 million or 78.6% from $3.1 million to $5.5 million for the three months ended March 31, 2024 primarily due to an increase in the depletion rate. On a per unit basis, depletion expense was $8.43 per BOE and $4.86 per BOE for the three months ended March 31, 2024 and 2023, respectively. The depletion rate of our unit of production calculation increased due to decreases in proved reserve volumes as well as increases in our depletable base due to our SCOOP/STACK Acquisitions and capital expenditures since March 31, 2023. Our proved reserves volumes have decreased since the prior year period primarily due to oil and natural gas volumes produced combined with a reduction in the SEC prices used in calculating proved reserves since the prior year period.

General and Administrative Expenses

General and administrative expenses for the three months ended March 31, 2024 increased minimally over the prior year period. General and administrative expenses were $1.9 million for the three months ended March 31, 2024 compared to $1.8 million for the prior year period. The increase primarily relates to an increase in salary and employee benefits due to additional personnel added as additional assets were acquired. On a per unit basis, general and administrative expenses were $2.85 per BOE and $2.84 per BOE for the three months ended March 31, 2024 and 2023, respectively.

Stock-based Compensation Expense

Stock-based compensation expense for the three months ended March 31, 2024 remained flat at $0.5 million for each period.

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Net Gain (Loss) on Derivative Contracts

Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the unaudited condensed consolidated statements of operations. The amounts recorded on the unaudited condensed consolidated statements of operations related to derivative contracts represent the (i) gains (losses) related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) gains (losses) on settlements of derivative contracts for positions that have settled or been realized. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized (gains) losses on our average realized prices for the periods presented. As a result of our SCOOP/STACK Acquisitions in the current quarter and our acquisitions during fiscal year 2022 and the corresponding borrowings on our Senior Secured Credit Facility, we were required by terms set in the Senior Secured Credit Facility to hedge a portion of our production. The increase in commodity prices since entering into the hedges and the continued increase in forward commodity prices resulted in a realized loss on hedges for the current quarter and an unrealized loss on the mark-to-market of our hedges, respectively. As of March 31, 2024, we had $0.3 million derivative asset all of which was classified as current, and a $1.4 million derivative liability, all of which was classified as current.


	Three Months Ended
	March 31,
(in thousands, except per unit and per BOE amounts)	2024		2023		Variance		Variance %
Realized gain (loss) on derivative contracts	$	(120)	$	465	$	(585)	(125.8)	%
Unrealized gain (loss) on derivative contracts		(1,063)		(195)		(868)	445.1	%
Total net gain (loss) on derivative contracts	$	(1,183)	$	270	$	(1,453)	(538.1)	%

Average realized crude oil price per BBL	$	73.06	$	70.65	$	2.41	3.4	%
Cash effect of oil derivative contracts per BBL		(0.60)		—		(0.60)	—	%
Crude oil price per BBL (including impact of realized derivatives)	$	72.46	$	70.65	$	1.81	2.6	%

Average realized natural gas price per MCF	$	2.77	$	9.80	$	(7.03)	(71.7)	%
Cash effect of natural gas derivative contracts per MCF		—		0.21		(0.21)	(100)	%
Natural gas price per MCF (including impact of realized derivatives)	$	2.77	$	10.01	$	(7.24)	(72.3)	%

Interest Expense

Interest expense increased $0.5 million for the three months ended March 31, 2024 compared to the prior year period primarily due to borrowings drawn on our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions during the current period.

Income Tax (Expense) Benefit

For the three months ended March 31, 2024, we recognized income tax expense of $0.2 million on net income before income taxes of $0.4 million compared to income tax expense of $3.9 million on net income before income taxes of $17.9 million for the three months ended March 31, 2023. The effective tax rates were 35.2% and 22.0% for three months ended March 31, 2024 and 2023, respectively. The effective tax rate increased compared to the prior year period as projected state income taxes have become a larger component of our overall income tax expense during the period.

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Nine Months Ended March 31, 2024 and 2023

We reported net income of $2.8 million and $35.1 million for the nine months ended March 31, 2024 and 2023, respectively. The following table summarizes the comparison of financial information for the periods presented:


	Nine Months Ended
	March 31,
(in thousands, except per unit and per BOE amounts)	2024		2023		Variance		Variance %
Net income (loss)	$	2,845	$	35,051	$	(32,206)	(91.9)	%
Revenues:
Crude oil		38,913		40,062		(1,149)	(2.9)	%
Natural gas		17,943		58,816		(40,873)	(69.5)	%
Natural gas liquids		7,794		11,462		(3,668)	(32.0)	%
Total revenues		64,650		110,340		(45,690)	(41.4)	%
Operating costs:
Lease operating costs:
CO₂ costs		4,241		6,027		(1,786)	(29.6)	%
Ad valorem and production taxes		4,008		7,001		(2,993)	(42.8)	%
Other lease operating costs		28,616		34,699		(6,083)	(17.5)	%
Depletion, depreciation, and accretion:
Depletion of full cost proved oil and natural gas properties		13,680		9,598		4,082	42.5	%
Accretion of asset retirement obligations		1,080		841		239	28.4	%
General and administrative expenses:
General and administrative		5,937		6,165		(228)	(3.7)	%
Stock-based compensation		1,585		1,155		430	37.2	%
Other income (expense):
Net gain (loss) on derivative contracts		(1,183)		513		(1,696)	(330.6)	%
Interest and other income		283		26		257	988.5	%
Interest expense		(584)		(404)		(180)	44.6	%
Income tax (expense) benefit		(1,174)		(9,938)		8,764	(88.2)	%

Production:
Crude oil (MBBL)		519		501		18	3.6	%
Natural gas (MMCF)		6,091		7,065		(974)	(13.8)	%
Natural gas liquids (MBBL)		295		325		(30)	(9.2)	%
Equivalent (MBOE)⁽¹⁾		1,829		2,004		(175)	(8.7)	%
Average daily production (BOEPD)⁽¹⁾		6,651		7,314		(663)	(9.1)	%

Average price per unit⁽²⁾:
Crude oil (BBL)	$	74.98	$	79.96	$	(4.98)	(6.2)	%
Natural gas (MCF)		2.95		8.32		(5.37)	(64.5)	%
Natural Gas Liquids (BBL)		26.42		35.27		(8.85)	(25.1)	%
Equivalent (BOE)⁽¹⁾		35.35		55.06		(19.71)	(35.8)	%

Average cost per unit:
Operating costs:
Lease operating costs:
CO₂ costs	$	2.32	$	3.01		(0.69)	(22.9)	%
Ad valorem and production taxes		2.19		3.49		(1.30)	(37.2)	%
Other lease operating costs		15.65		17.31		(1.66)	(9.6)	%
Depletion of full cost proved oil and natural gas properties		7.48		4.79		2.69	56.2	%
General and administrative expenses:
General and administrative		3.25		3.08		0.17	5.5	%
Stock-based compensation		0.87		0.58		0.29	50.0	%

(1)	Equivalent oil reserves are defined as six MCF of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.

(2)	Amounts exclude the impact of cash paid or received on the settlement of derivative contracts since we did not elect to apply hedge accounting.

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Revenues

Crude oil, natural gas and NGL revenues were $64.7 million and $110.3 million for the nine months ended March 31, 2024 and 2023, respectively. The decrease in revenues is primarily due to the decrease in our average realized price per BOE coupled with a decrease in our sales volumes. Our average realized commodity price (excluding the impact of derivative contracts) for the nine months ended March 31, 2024 decreased approximately $19.71 per BOE, or 35.8%, over the prior year period. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, inventory storage levels, basis differentials and other factors. Realized natural gas prices decreased 64.5% from the prior year period, which was the largest portion of the driver of the decrease in revenues. This was partially attributed to the prior year period benefit of strong natural gas price differentials received at the Jonah Field where we realized an average natural gas price of $12.99 per MCF in the prior year period compared to $4.16 in the current year period. Average daily equivalent production decreased 9.1% from 7,314 BOEPD in the prior year period to 6,651 BOEPD in the current period as a result of natural production declines in our properties combined with operational issues and downtime at our Barnett Shale property. We began experiencing production declines and downtime in April 2023 at Barnett. Production declines were primarily related to compression issues due to excessive heat, downtime in the gathering and processing system, pipeline rerouting and optimization, and our operator’s decision to temporarily shut-in certain low margin wells. As of March 31, 2024, the midstream issues have been moderated, but due to low natural gas prices the shut-in wells remain offline which has continued to negatively impact production volumes. The overall decrease in production was partially offset by the acquisitions of non-operated working interests in the SCOOP/STACK in February 2024 and first production at our wells in the Chaveroo Field in early February 2024, which collectively increased production for the nine months ended March 31, 2024 by approximately 340 BOEPD.

Lease Operating Costs

Ad valorem and production taxes were $4.0 million and $7.0 million for the nine months ended March 31, 2024 and 2023, respectively. On a per unit basis, ad valorem and production taxes were $2.19 per BOE and $3.49 per BOE for the nine months ended March 31, 2024 and 2023, respectively. The decrease in ad valorem and production taxes is primarily due to decreases in oil and natural gas prices as well as decreased production volumes described above as production taxes are based on sales at the wellhead.

The following table summarizes CO₂costs per Mcf and CO₂volumes for the nine months ended March 31, 2024 and 2023. CO₂ purchase costs are for the Delhi Field. Under our contract with the Delhi Field operator, purchased CO₂ is priced at 1% of the realized oil price in the field per MCF, plus sales taxes and transportation costs as per contract terms.


	Nine Months Ended
	March 31,
	2024		2023		Variance		Variance %
CO₂ costs per MCF	$	0.97	$	1.01	$	(0.04)	(4.0)	%
CO₂ volumes (MMCF per day, gross)		67.0		90.8		(23.8)	(26.2)	%

The $1.8 million decrease in CO₂costs for the nine months ended March 31, 2024 was primarily due to a 26.2% decrease in purchased CO₂volumes combined with a 4.0% decrease in CO₂ costs per MCF, which was driven by a decrease in our average realized oil price and the suspension of CO₂ purchases at the end of February 2024 due to maintenance on the CO₂ pipeline. CO₂ volumes injected were also reduced compared to prior year period due to a reduction in CO₂ purchase nominations and higher ambient temperatures in the Delhi Field during the fiscal year. In the prior year period, CO₂ purchase nominations were higher to compensate for reduced reservoir pressure. CO₂ purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. We do not have any ownership in the CO₂ pipeline which is owned and operated by Denbury. On a per unit basis, CO₂ costs were $2.32 per BOE and $3.01 per BOE for the nine months ended March 31, 2024 and 2023, respectively.

Other lease operating costs decreased $6.1 million, or 17.5%, compared to the prior year period primarily due to lower production combined with the lower commodity price environment. On a per unit basis, other lease operating costs decreased to $15.65 per BOE for the nine months ended March 31, 2024 from $17.31 per BOE in the year-ago quarter. The largest decrease in operating costs is at our Barnett Shale properties and the Delhi Field. At the Barnett Shale,

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significant cost savings efforts are being prioritized due to the lower realized natural gas prices and the shut-in of certain low margin wells at current natural gas prices. We are incurring lower operating costs in all cost categories, especially lower water hauling costs and lower gathering, transportation and processing charges. At Delhi Field, we have seen lower electricity charges due to lower commodity prices.

Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased $4.1 million or 42.5% from $9.6 million to $13.7 million for the nine months ended March 31, 2024 primarily due to an increase in the depletion rate. On a per unit basis, depletion expense was $7.48 per BOE and $4.79 per BOE for the nine months ended March 31, 2024 and 2023, respectively. The depletion rate of our unit of production calculation increased due to decreases in proved reserve volumes as well as increase in our depletable base due to our SCOOP/STACK Acquisitions and capital expenditures since the prior year period. Our proved reserves volumes have decreased since the prior year period primarily due to oil and natural gas volumes produced, combined with a reduction in the SEC prices used for calculating proved reserves since the prior year period.

General and Administrative Expenses

General and administrative expenses for the nine months ended March 31, 2024 decreased $0.2 million, or 3.7%, to $5.9 million compared to $6.2 million for the prior year period. The decrease primarily relates to lower consulting fees totaling approximately $0.3 million related to our search for a CEO in the prior year period. On a per unit basis, general and administrative expenses were $3.25 per BOE and $3.08 per BOE for the nine months ended March 31, 2024 and 2023, respectively. The slight increase on a per unit basis is primarily the result of the decrease in production for the current year period.

Stock-based Compensation Expense

Stock-based compensation expense for the nine months ended March 31, 2024 increased $0.4 million to $1.6 million compared to $1.2 million for the prior year period. The increase is primarily due to the addition of new personnel, including our CEO and COO added since the prior year period and the associated new awards granted during the current year period.

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Net Gain (Loss) on Derivative Contracts


	Nine Months Ended
	March 31,
(in thousands, except per unit and per BOE amounts)	2024		2023		Variance		Variance %
Realized gain (loss) on derivative contracts	$	(120)	$	(1,481)	$	1,361	(91.9)	%
Unrealized gain (loss) on derivative contracts		(1,063)		1,994		(3,057)	(153.3)	%
Total net gain (loss) on derivative contracts	$	(1,183)	$	513	$	(1,696)	(330.6)	%

Average realized crude oil price per BBL	$	74.98	$	79.96	$	(4.98)	(6.2)	%
Cash effect of oil derivative contracts per BBL		(0.23)		(0.49)		0.26	(53.1)	%
Crude oil price per BBL (including impact of realized derivatives)	$	74.75	$	79.47	$	(4.72)	(5.9)	%

Average realized natural gas price per MCF	$	2.95	$	8.32	$	(5.37)	(64.5)	%
Cash effect of natural gas derivative contracts per MCF		—		(0.17)		0.17	(100)	%
Natural gas price per MCF (including impact of realized derivatives)	$	2.95	$	8.15	$	(5.20)	(63.8)	%

Interest Expense

Interest expense increased $0.2 million for the nine months ended March 31, 2024 compared to the prior year period primarily due to borrowings drawn on our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions during the current year.

Income Tax (Expense) Benefit

For the nine months ended March 31, 2024, we recognized income tax expense of $1.2 million on net income before income taxes of $4.0 million compared to income tax expense of $9.9 million on net income before income taxes of $45.0 million for the nine months ended March 31, 2023. The effective tax rates were 29.2% and 22.1% for three months ended March 31, 2024 and 2023, respectively. The effective tax rate increased compared to the prior year period as projected state income taxes have become a larger component of our overall income tax expense during the period.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements. The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires that we select certain accounting policies and make estimates and assumptions that affect the reported amounts of the assets, liabilities, and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported amounts of revenues and expenses during the reporting period. These policies, together with our estimates, have a significant effect on our unaudited condensed

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consolidated financial statements. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended June 30, 2023.

Item 3. Quantitative and Qualitative Disclosures About Market Risks

Derivative Instruments and Hedging Activity

We are exposed to various risks, including energy commodity price risk, such as price differentials between the NYMEX commodity price and the index price at the location where our production is sold. When oil, natural gas, and natural gas liquids prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we monitor commodity prices to identify the potential need for the use of derivative financial instruments to provide partial protection against declines in oil and natural gas prices. We do not enter into derivative contracts for speculative trading purposes. In accordance with our Senior Secured Credit Facility, we may be required to enter into hedges if we meet certain utilization levels of the borrowing base under the credit facility. We intend to remain in compliance with these covenants and will enter into derivative contracts from time to time to meet the requirements. Additionally, depending on market conditions, financial and other considerations we may enter into additional hedges to meet our objectives of increasing value to shareholders.

We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competitive market makers. For the derivative contracts settled during fiscal 2024 and 2023, we did not post collateral. We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging, (“ASC 815”). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 7, “Derivatives” to our unaudited condensed consolidated financial statements for more details.

Interest Rate Risk

We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents. Additionally, any borrowings under the Senior Secured Credit Facility will bear interest, at our option, at either SOFR plus 2.80%, which includes a 0.05% credit spread adjustment from LIBOR, subject to a minimum SOFR of 0.50%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%. SOFR rates are sensitive to the period of contract and market volatility, as well as changes in forward interest rate yields. Under our current practices, we do not use interest rate derivative instruments to manage exposure to interest rate changes.

Item 4. Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s (“SEC”) rules and forms. This information is accumulated and communicated to our management, including our Principal Executive Officer and Principal Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

As required by SEC Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15(d)-15(e)) as of the end of the quarter covered by this report. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. Based on the foregoing, our Principal Executive Officer and Principal Financial Officer concluded that as of March 31, 2024 our disclosure controls and procedures are effective in ensuring that the information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms.

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Under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, during the quarter ended March 31, 2024, we have determined that there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

See Note 10, “Commitments and Contingencies” to our unaudited condensed consolidated financial statements in Item 1. Condensed Consolidated Financial Statements (Unaudited) for a description of any legal proceedings, which is incorporated herein by reference.

Item 1A. Risk Factors

Our Annual Report on Form 10-K for the year ended June 30, 2023 includes a detailed description of our risk factors.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

The table below summarizes information about the Company's purchases of its equity securities during the three months ended March 31, 2024.


				(c) Total number	(d) Maximum dollar value
	(a) Total number			of shares	of shares that may yet be
	of shares			purchased as part	purchased under the
	purchased and	(b) Average price		of public announced	plans or programs
Period	received ⁽¹⁾	paid per share ⁽¹⁾		plans or programs⁽²⁾	(in thousands)⁽²⁾
January 2024	400	$	5.50	400	$	21,150
February 2024	150,799		5.35	140,272		20,403
March 2024	741		5.90	—		20,403

(1)	During the three months ended March 31, 2024, all of the shares received outside of publicly announced plans or programs were surrendered by employees in exchange for the payment of tax withholding upon the vesting of restricted stock awards.

(2)

On September 8, 2022, the Company’s Board of Directors approved a share repurchase program, under which the Company is authorized to repurchase up to $25.0 million of its common stock in the open market through December 31, 2024. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will depend on a variety of factors, including management’s assessment of the intrinsic value of the Company’s shares, the market price of the Company's common stock, the Company’s capital needs and resources, general market and economic conditions, and applicable legal requirements. The value of shares authorized for repurchase by the Company's Board of Directors does not require the Company to repurchase such shares or guarantee that such shares will be repurchased, and the program may be suspended, modified, or discontinued at any time without prior notice. In November 2023, the Company entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan is effective until June 30, 2024, unless extended, renewed or terminated by the Company, and has a maximum authorized amount of $0.8 million over that period. The Company may alter the terms of the plan from time to time to the extent it determines changes are necessary to achieve the intended objectives of the repurchase program.

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Item 3. Defaults Upon Senior Securities

Not Applicable.

Item 4. Mine Safety Disclosures

Not Applicable.

Item 5. Other Information

None.

Item 6. Exhibits

The following documents are included as exhibits to the Quarterly Report on Form 10-Q. Those exhibits incorporated by reference are so indicated by the information supplied with respect thereto. Those exhibits which are not incorporated by reference are attached hereto.









3.1		Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 of our Quarterly Report on Form 10-Q filed February 8, 2023).
3.3		Amended and Restated Bylaws (incorporated by reference to Exhibit 3.3 of our Annual Report on Form 10- filed September 13, 2023)
10.11*		Purchase and Sale Agreement, dated February 12, 2024, between Evolution Petroleum Corporation and Red Sky Resources III, LLC
10.12*		Purchase and Sale Agreement, dated February 12, 2024, between Evolution Petroleum Corporation and Red Sky Resources IV, LLC
10.13*		Purchase and Sale Agreement, dated February 12, 2024, between Evolution Petroleum Corporation and Coriolis Energy Partners I, LLC
10.2.11*		Amendment to the Credit Agreement dated February 12, 2024 between Evolution Petroleum Corporation and MidFirst Bank
31.1**		Certification of Principal Executive Officer Pursuant to Rule 15D-14 of the Securities Exchange Act of 1934, as Amended as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2**		Certification of Principal Financial Officer Pursuant to Rule 15D-14 of the Securities Exchange Act of 1934, as Amended as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1**		Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**		Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*		Inline XBRL Instance Document
101.SCH*		Inline XBRL Taxonomy Extension Schema Document
101.CAL*		Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*		Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*		Cover Page Interactive Data File (embedded within the Inline XBRL document)

* Attached hereto.

** Furnished herewith.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	Evolution Petroleum Corporation
Date: May 8, 2024	By:	/s/ KELLY W. LOYD
		Kelly W. Loyd President and Chief Executive Officer (Principal Executive Officer) and Director
	By:	/s/ RYAN STASH
		Ryan Stash Senior Vice President and Chief Financial Officer (Principal Financial Officer) and Treasurer

EXHIBIT 10.11

PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement (the “Agreement”) is entered into on January 5, 2024 (the “Execution Date”), but to be effective as of 12:01 a.m. on November 1, 2023 (the “Effective Date”), by and among Red Sky Resources III, LLC, a Colorado limited liability company (“Seller”), and Evolution Petroleum Corporation, a Nevada corporation (“Buyer”). Each of the Seller or Buyer is sometimes individually referred to herein as a “Party” and collectively as the “Parties”.

RECITALS

WHEREAS, Seller owns certain oil, gas and mineral leases and other assets located in Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens Counties, Oklahoma; and

WHEREAS, Seller desires to sell and Buyer desires to purchase all of Seller’s interest in and to the Properties (as defined in Section 1.1 below) upon the terms and conditions set forth in this Agreement.

NOW, THEREFORE, in consideration of the mutual promises contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Buyer and Seller agree as follows:

ARTICLE I

PROPERTIES DEFINED

1.1Properties. As used in this Agreement, the term “Property” (when used in the singular) and “Properties” (when used in the plural) shall refer to the following, except to the extent any of the same constitutes an Excluded Asset (as defined in Section 1.2 below):

(a)the oil, gas and mineral leases (including all leasehold estates created thereby) described in Exhibit A-1 attached hereto (collectively, the “Leases”), insofar as the Leases cover and relate to the land and depths covered by the Leases (collectively, the “Lands”), together with corresponding interests in and to all the property and rights incident thereto, including all Royalties (as defined in Section 3.1(p)), overriding Royalty interests, rights in any pooled or unitized acreage by virtue of the Lands being a part thereof, all production from the pool or unit allocated to any such Lands, and all interests in any wells within the pool or unit associated with the Lands;

(b)all oil, gas and mineral wells (whether producing or non-producing) located on the Leases or lands pooled or unitized therewith, including, without limitation, those certain wells described on Exhibit A-2 (collectively, the “Wells”);

(c)all (i) oil, gas, and other hydrocarbons (“Hydrocarbons”) produced from or allocated to the Wells with respect to all periods subsequent to the Effective Date and all proceeds therefrom, including without limitation, all Hydrocarbons in storage or existing in pipelines, plants and tanks (including inventory and line fill) and upstream of the sales meter as of the Effective Date and all other Hydrocarbons produced from or allocated to the Wells after the Effective Date, and (ii) all water, injection and other wells (such wells, including the non-oil and gas wells set forth on Exhibit A-3 attached hereto, the “Other Wells”), in each case, located on any of the Leases or Lands or on any other lease with which any such Lease has been pooled or unitized, whether producing, operating, plugged, permanently abandoned, shut-in or temporarily abandoned or any of the Surface Rights (as defined in Section 1.1(f));

include, without limitation, all contracts and contractual rights, area of mutual interest agreements; joint venture agreements; confidentiality agreements, land and title records (including abstracts of title and title opinions), environmental, production, engineering and accounting records, easements, rights of way, obligations, and interests, including all farmout and farmin agreements, operating agreements, operations records, bottom hole agreements, crude oil, condensate and natural gas purchase and sale, gathering, transportation and marketing agreements; Hydrocarbon storage agreements; acreage contribution agreements production sales and purchase contracts, unitization and pooling agreements, communitization agreements, saltwater disposal agreements, surface leases, surface use agreements, division and transfer orders, geological files and geophysical data, daily drilling reports, well records including well data and logs; balancing agreements, pooling declarations or agreements, unitization agreements, processing agreements, facilities or equipment leases, exploration agreements, participation agreements, exchange agreements and other similar contracts and agreements, and any and all amendments, ratifications or extensions of the foregoing, including (i) any claims for take or pay or other similar payments arising before or after the Effective Date to the extent related to production of Hydrocarbons on or after the Effective Date, (ii) all rights of Seller and its Affiliates that are currently serving as operator under any joint operating agreement to serve as operator under such joint operating agreement, and (iii) to the extend not covered in (i) – (ii), any and all contracts, agreements and instruments by which the Properties are bound, or that relate to or are otherwise applicable to the Properties, insofar as such contracts are valid and existing and applicable to the Properties, or the oil, gas, and other Hydrocarbons produced from the Properties or attributable to the Properties in storage owned by Seller above custody transfer point at the Effective Date or produced on and after the Effective Date, and all proceeds attributable thereto, and other contracts or agreements covering or affecting any or all of the other Properties described herein (collectively, the “Contracts”), but exclusive of any Contracts set forth on Schedule 1.1(d) or relating to the Excluded Assets;

(e)all rights and interests in, under or derived from all unitization and pooling agreements, communitization agreements or orders (including but not limited to division and transfer orders) in effect with respect to any of the Leases, Wells or Other Wells and the units set forth on Exhibit A-4 attached hereto created thereby (the “Units”);

(f)except as set forth on Schedule 1.1(f), all surface leases, surface rights, surface use agreements, permits, licenses, servitudes, easements, surface and road use agreements, railroad crossing authorizations, ingress and egress agreements, water rights and rights-of-way to the extent primarily used or held for use in connection with any of the Properties (collectively, the “Surface Rights”), including the Surface Rights set forth on Exhibit A-5 attached hereto;

(g)all structures, equipment, machinery, fixtures, physical assets and facilities, pipe, pipelines, flowlines, gathering systems and appurtenances thereto, inventory, improvements, and other personal, mixed, or movable property, including vehicles and rolling stock, or interests whether located on or off the Lands covered by the Leases, used primarily in connection with the ownership or operation of the Properties, including the equipment, machinery fixtures, physical assets and facilities, pipe, pipelines, flowlines, gathering systems and appurtenances thereto, fixtures, inventory, improvements, and other personal, mixed, or movable property or interests and other personal, moveable and mixed property, operational and nonoperational, known or unknown, located on any of the other Properties and that are primarily used or held for use in connection therewith (collectively, the “Personal Property”);

(h)All claims, rights and causes of action, including, without limitation, causes of action for breach of warranty, against third parties, asserted and unasserted, known and unknown, but only to the extent such claims, rights and causes of action affect the value of any of the items described in Sections 1.1 (a) through (g) after the Effective Time, and where necessary to give effect to the assignment of such rights, claims and causes of action, Seller grants to Buyer the right to be subrogated to such rights, claims and causes of action; and

(i)all Imbalances (as defined in Section 3.1(i)) relating to the Properties.

1.2Excluded Assets. Notwithstanding anything to the contrary contained herein, the Properties shall not include, and there is excepted, reserved, and excluded from the purchase and sale contemplated hereby, the properties described on Exhibit A-6 attached hereto.

1.3Purchase and Sale. Subject to the other terms and conditions of this Agreement, Buyer agrees to purchase from Seller and Seller agrees to sell, assign, and deliver to Buyer all of Seller’s right, title and interest (whether present, contingent or reversionary) in and to the Properties.

1.4Specified Liabilities.

(a)Notwithstanding anything contained in this Agreement to the contrary, Buyer shall not assume and shall not be obligated to assume or be obliged to pay, perform, or otherwise discharge any obligations or liabilities of Seller to the extent that they are Specified Liabilities (defined below).

(b)For purposes of this Agreement, the term “Specified Liabilities” shall mean, with respect to Seller, any and all claims, obligations, causes of action, payments, charges, demands, judgments, assessments, liabilities, losses, damages, penalties, fines and costs and expenses, including any attorneys’ fees, legal or other expenses incurred in connection therewith, arising out of any of the following:

(i)death or physical injury to any employees of Seller related to or arising out of Seller’s ownership or operation of the Properties and occurring prior to the Closing Date;

(ii)claims for compensation or reimbursement of Seller’s employees for work performed with respect to the Properties prior to the Closing Date (but excluding any Property Expenses);

(iii)offsite transport or disposal, or arrangement for transport or disposal by Seller, of any Hazardous Substances (as defined in Section 3.1(h)) from the Properties that occurred prior to the Effective Date to the extent chargeable to Seller’s Working Interest (as defined in Section 3.1(w)) in the Properties during Seller’s period of ownership thereof or any other liabilities associated with the disposal or transportation of any Hazardous Substances from the property associated with the Properties to any location not on such property or lands pooled or unitized therewith prior to Closing;

(iv)Imbalances relating to the Properties that are not set forth on Schedule 6.19;

(v)the failure to pay, underpayment, or incorrect payment of any and all Royalties and other Burdens with respect to any of Seller’s ownership of the Properties in each case to the extent (i) not attributable to suspense funds, (ii) attributable to the period that Hydrocarbons were produced and marketed from any Properties during Seller’s period of ownership of the Properties prior to the Effective Date and (iii) chargeable to Seller’s Working Interest in the Properties;

(vi)attributable to or arising out of (i) the Excluded Assets or (ii) Seller Taxes (as defined in Section 3.1(q)) imposed on or with respect to the ownership or operation of the Properties or the production of Hydrocarbons or the receipt of proceeds therefrom that are attributable to any Tax period or portion thereof ending before the Effective Date;

(vii)all indebtedness for borrowed money of Seller;

(viii)Taxes (as defined in Section 3.1(s)) imposed on or with respect to the ownership or operation of the Properties or the production of Hydrocarbons or the receipt of proceeds therefrom that are attributable to any tax period or portion thereof ending before the Effective Date;

(ix)all Encumbrances (as defined in Section 3.1(f)) on the Properties except for Permitted Encumbrances (as defined in Section 3.1(n)); and

(x)any unpaid Royalties with respect to Seller’s ownership or operation of the Properties occurring prior to Closing.

ARTICLE II

PURCHASE PRICE AND DEPOSIT

2.1Purchase Price. The purchase price for the Properties shall be Eighteen Million Five Hundred and Twelve Thousand Dollars ($18,512,000) (the “Purchase Price”), adjusted in accordance with Section 2.4 (the “Adjusted Purchase Price”) and shall be paid as follows: Buyer shall pay Seller a Deposit (as defined in Section 2.3) upon execution of this Agreement and shall pay the balance of the Adjusted Purchase Price (less the Deposit) at Closing (as defined in Section 4.1) as further provided in this Agreement.

2.2Purchase Price Allocation. The Purchase Price has been allocated by Buyer among the various Properties in the manner and in accordance with the respective values set forth in Schedule 2.2. If any adjustment is made to the Purchase Price pursuant to Section 2.4 of this Agreement, a corresponding adjustment shall be made to the portion of the Purchase Price allocated to the affected Property in Schedule 2.2 (the “Allocation”). Buyer and Seller agree that the Purchase Price shall be allocated among the Wells as set forth on Schedule 2.2 (the “Allocated Values”).

2.3Deposit. Contemporaneously with the execution of this Agreement, Buyer has deposited with Seller an amount equal to seven and one-half percent (7.5%) of the Purchase Price, or One Million Three Hundred and Eighty-Eighty Thousand Four Hundred Dollars ($1,388,400) (the “Deposit”), in immediately available funds according to the wire instructions of Seller. The Deposit is nonrefundable to Buyer unless the transactions contemplated herein fail to close due to the reasons set forth in Section 10.1(a), (b), (d), or Section 10.2(b). The Deposit shall be held in an interest-bearing account in an institution reasonably agreeable to the Parties.

2.4Accounting Adjustments.

(a)The Purchase Price shall be adjusted upward (without duplication), and such adjustment shall be reflected on the Preliminary Settlement Statement (as defined in Article XI) and the Final Adjustment Statement (defined below), by the following amounts:

(i)The aggregate amount of all ordinarily incurred operating expenses (including costs of insurance, bonds and other guarantees) and all capital expenditures incurred in the drilling, completion, ownership and operation of the Properties, and third party overhead costs charged or chargeable to the Properties under the relevant operating agreement or unit agreement, if any, but excluding any Income Taxes (as defined in Section 3.1(j), Asset Taxes (as defined in Section 3.1(b)), and Transfer Taxes (as defined in Section 12.1) but excluding the general administrative or overhead expenses of Seller or its Affiliates (collectively, the “Property Expenses”) incurred and paid by Seller during the period from the Effective Date to the Closing Date in respect of the ownership of the Properties, but excluding costs and expenses that are Seller’s responsibility pursuant to Section 2.4(b)(ii) below;

(ii)The amount of any drilling and completion related costs and expenses paid by Seller for those certain Wells categorized as Permitted, Pre-Permitted or Proved Undeveloped on Schedule 2.4, regardless of whether such costs were or are incurred prior to or after the Effective Date;

(iii)The aggregate amount of Hydrocarbon inventories from the Properties in storage on the Effective Date and produced for the account of Seller with respect to the Properties prior to the Effective Date (as shown by the actual gauging reports and exclusive of tank bottoms), net of any Royalties, overriding Royalties, nonparticipating Royalties, net profits interests, production payments, carried interests, reversionary interests and other Burdens on, measured by or payable out of such Hydrocarbon inventories (other than Property Expenses, other expenses taken into account in Section 2.4(b), Income Taxes, Asset Taxes, and Transfer Taxes) directly incurred in earning or receiving such proceeds);

(iv)The amount of all prepaid expenses of bonuses; rentals; and cash calls to third party operators, to the extent applying to the ownership or operation of the Properties paid by Seller from and including the Effective Date;

(v)The amount of all prepaid expenses of bonuses; rentals; and cash calls to third party operators paid by Seller with respect to those certain Wells categorized as Permitted, Pre-Permitted or Proved Undeveloped on Schedule 2.4;

(vi)The amount of any ad valorem, property, excise, severance, production, sales, use, or similar Taxes based upon the operation or ownership of the Properties or the production of Hydrocarbons therefrom, arising after the Effective Date allocated to Buyer in accordance with Section 18.1(b) but paid or otherwise economically borne by Seller;

(vii)An amount by which the aggregate amount of all Seller Title Credits to which Seller is entitled pursuant to Section 3.6 of this Agreement exceeds two percent (2.0%) of the Purchase Price before any adjustment pursuant to this Section 2.4; and

(viii)Any other amount provided for elsewhere in this Agreement or otherwise agreed upon in writing by Seller and Buyer.

(b)The Purchase Price shall be adjusted downward (without duplication), and such adjustment shall be reflected on the Preliminary Settlement Statement and the Final Adjustment Statement, by the following amounts:

(i)Amounts received (net of applicable Royalties and other Lease Burdens paid out, and of production, severance, and similar Taxes) by Seller for the sale of Hydrocarbons produced and sold from the Properties during the period from the Effective Date to the Closing Date (other than expenses taken into account pursuant to Section 2.4(a), Income Taxes, Asset Taxes, and Transfer Taxes) to the extent that such amount has been received by Seller and not remitted or paid to Buyer;

(ii)To the extent paid by Buyer, the amount of any drilling and completion related costs and expenses for those certain Wells categorized as Producing or Drilled Uncompleted on Schedule 2.4, regardless of whether such costs were or are incurred prior to or after the Effective Date;

(iii)An amount by which the aggregate amount of all Title Defect Amounts with respect to all Title Defect Properties as determined in Section 3.5 exceeds two percent (2.0%) of the

Purchase Price before any adjustment pursuant to this Section 2.4, net of any adjustments on account of Seller Title Credits to which Seller is entitled pursuant to Section 2.4(a)(ii) of this Agreement;

(iv)An amount equal to all Property Expenses paid by or on behalf of Buyer that are attributable to the Properties during the period prior to the Effective Date, excluding any Property Expenses those certain Wells categorized as Permitted, Pre-Permitted or Proved Undeveloped on Schedule 2.4;

(v)If Seller makes the election under Section 3.5 and Section 3.7 with respect to a Title Defect, the Title Defect Amount with respect to such Title Defect if the Title Defect Amount has been determined as of or prior to the Closing;

(vi)The amount, if any, of Imbalances owed by Seller, multiplied by $2.50 per MMBtu, or, to the extent that applicable Contracts provide for cash balancing, the actual cash balance amount determined to be owed by Seller as of the Effective Date;

(vii) The amount of any ad valorem, property, excise, severance, production, sales, use, Asset Taxes, or similar Taxes based upon the operation or ownership of the Properties or the production of Hydrocarbons therefrom, arising after the Effective Date allocated to Seller in accordance with Section 18.1(b) but paid or otherwise economically borne by Buyer;

(viii)The amount of the unassignable Properties set forth on Schedule 1.1(d) and Schedule 1.1(f);

(ix)The Allocated Value of the Properties excluded from the transactions contemplated hereby pursuant to Section 17.1(a)(ii), Section 16.1(a), Section 16.2(a) or (b), and Section 14.1(c); and

(x)Any other amount provided for elsewhere in this Agreement or otherwise agreed upon in writing by Seller and Buyer.

(c)As soon as reasonably practicable after the Closing, but not later than the ninetieth (90th) day after the Closing Date (the “Final Settlement Date”), Seller shall determine if any additional adjustments (whether the same be made to account for expenses or revenues not considered in making the adjustments made at Closing, or to correct errors made in such adjustments) should be made beyond those made at Closing. Seller shall present Buyer with a statement (the “Final Adjustment Statement”) setting forth Seller’s good faith determination of such additional adjustments, if any, to the Purchase Price and supporting documentation as is reasonably necessary to support the Final Adjustment Statement (the “Final Price”). As soon as practicable, and in any event within thirty (30) days after receipt of the Final Adjustment Statement, Buyer shall return to Seller a written report containing any proposed changes to the Final Adjustment Statement and an explanation of any such changes and the reasons therefor (the “Dispute Notice”). Any changes not so specified in the Dispute Notice shall be deemed waived, and Seller’s determinations with respect to all such elements of the Final Adjustment Statement that are not addressed specifically in the Dispute Notice shall prevail. If the Final Price set forth in the Final Adjustment Statement is mutually agreed upon in writing by Seller and Buyer, without limiting Section 18.1(a), the Final Adjustment Statement and the Final Price, shall be final and binding on the Parties and not subject to further audit or arbitration. Any difference in the Adjusted Purchase Price as paid at Closing pursuant to the Preliminary Settlement Statement (defined below) and the Final Price shall be paid by appropriate payments from Seller to Buyer or from Buyer to Seller within ten (10) Business Days following the later to occur of Seller’s delivery of the Final Adjustment Statement or final determination of such owed amounts in

accordance herewith. Following such additional adjustments, no further adjustments shall be made under this Section 2.4.

2.5Disputes. Seller and Buyer shall work together in good faith to resolve any matters addressed in any Dispute Notice delivered pursuant to Section 2.4. If Seller and Buyer are unable to resolve all of the matters addressed in the Dispute Notice within ten (10) Business Days after the delivery of such Dispute Notice to the other Party, either Party may, upon notice to the other Party, submit all unresolved matters addressed in the Dispute Notice to, the Oklahoma City, Oklahoma office of Eide Bailly, LLP, or, if such firm is not able or willing to serve, a nationally-recognized independent accounting firm or consulting firm mutually acceptable to both Buyer and Seller (the “Accounting Arbitrator”), for review and final determination by arbitration. If Buyer and Seller have not agreed upon a mutually acceptable alternate Person to serve as Accounting Arbitrator within ten (10) Business Days of receiving notice of Eide Bailly LLP’s unavailability, Seller shall, within ten (10) Business Days after the end of such initial ten (10) Business Day period, formally apply to the Oklahoma City, Oklahoma office of the American Arbitration Association to choose the Accounting Arbitrator. The Accounting Arbitrator shall conduct the arbitration proceedings in Oklahoma City, Oklahoma in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Section 2.5. The Accounting Arbitrator’s determination shall be made within forty-five (45) days after submission of the matters in dispute and shall be final and binding on all Parties, without right of appeal. In determining the proper amount of any adjustment to the Purchase Price, the Accounting Arbitrator shall be bound by the terms of Article II and may not increase the Purchase Price more than the increase proposed by Seller nor decrease the Purchase Price more than the decrease proposed by Buyer, as applicable. The Accounting Arbitrator shall act as an expert for the limited purpose of determining the specific disputed aspects of Purchase Price adjustments submitted by any Party and may not award damages, interest or penalties to any Party with respect to any matter. Seller and Buyer shall each bear their own legal and accounting fees and other costs of presenting its case to the Accounting Arbitrator. Seller shall bear one-half and Buyer shall bear one-half of the costs and expenses of the Accounting Arbitrator. Seller or Buyer (as applicable) shall make payment to the other Party within ten (10) days following the decision of the Accounting Arbitrator regarding any disputes resolved pursuant to this Section 2.5.

ARTICLE III

DOCUMENT REVIEW

3.1Definitions. As used in this Agreement, the following terms shall have the meanings set forth in this Section 3.1 (and all other capitalized terms in this Agreement that are not defined in this Section 3.1 shall have the meanings ascribed to such terms herein):

(a)The term “Affiliate” shall mean any Person that directly or indirectly, through one or more intermediaries, controls or is controlled by, or is under common control with, another Person. The term “control” and its derivatives with respect to any Person mean the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities, by contract or otherwise. Notwithstanding the foregoing, “Affiliates”, when used with respect to any Seller, shall only include the direct and indirect subsidiaries of Seller and shall not include any Seller Affiliates.

(b)The term “Asset Tax” shall mean ad valorem, property, excise, severance, production, sales, use and similar Taxes based upon the acquisition, ownership or operation of the Properties or the production of Hydrocarbons or the receipt of proceeds therefrom (excluding, for the avoidance of doubt, any Income Taxes and Transfer Taxes)

(c)The term “Burdens” shall mean any and all Royalties (including lessor’s Royalty), overriding Royalties, production payments, net profits interests and other burdens upon, measured by or payable out of production (excluding, for the avoidance of doubt, any Taxes).

(d)The term “Business Day” shall mean any day that is not a Saturday, Sunday or legal holiday in the State of Oklahoma or a federal holiday in the United States of America.

(e)The term “Defensible Title” means such right, title, or interest of Seller as of the Effective Time that: (i) entitles Seller in the aggregate to receive from its ownership interest in the Properties not less than the Net Revenue Interest shown for each of the Properties listed on Part I of Schedule 2.2, except for reductions in such Net Revenue Interests for revisions after payout or some other event which are disclosed on Part I of Schedule 2.2, if any; (ii) obligates Seller in the aggregate to bear a Working Interest not greater than the Working Interest shown for each of such Properties listed on Part I of Schedule 2.2 from each Subject Depth (as defined in Section 3.1(r)) as applicable, without increase throughout the productive life of each of such Properties, unless the Net Revenue Interest therein is increased in the same proportion; (iii) with respect to each of the Leases listed on Exhibit A-1, entitles Seller to not less than the number of Net Acres listed for such Lease in Part II of Schedule 2.2; (iv) is free and clear of all liens, Encumbrances, and defects except for Permitted Encumbrances (as defined in Section 3.1(n)); and (v) is free from reasonable doubt to the end that a prudent person engaged in the business of purchasing and owning, developing, and operating producing or non-producing oil and gas properties in the geographical areas in which they are located, with knowledge of all of the facts and their legal bearing, would be willing to accept the same acting reasonably.

(f)The term “Encumbrance” shall mean any lien, mortgage, security interest, pledge, charge, or similar encumbrance.

(g)The term “Governmental Agency” shall mean any federal, state, local, municipal, tribal or other government; any governmental, regulatory or administrative agency, commission, body or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, regulatory or taxing authority or power, and any court or governmental tribunal, including any tribal authority having or asserting jurisdiction.

(h)The term “Hazardous Substances” shall mean any pollutants, contaminants, toxins, materials, wastes, constituents, compounds or chemicals, classified as “hazardous wastes,” “hazardous substances,” “extremely hazardous substances,” “toxic,” or words of similar import pursuant to any Environmental Law (as defined in Section 13.1(c)), and shall also include petroleum, waste oil or petroleum constituents or by-products.

(i)The term “Imbalances” shall mean over-production or under-production or over-deliveries or under-deliveries subject to a make-up obligations with respect to Hydrocarbons produced from or allocated to the Properties, regardless of whether such over-production or under-production, or over-deliveries or under-deliveries, arise at the wellhead, pipeline, gathering system, plant, transportation, receipt point or other location and regardless of whether the same arises under contract or by operation of Law or otherwise, provided that “Imbalances” does not include any such item that is an Excluded Asset.

(j)The term “Income Taxes” shall mean all Taxes based upon, measured by, or calculated with respect to gross or net income, and franchise taxes based upon income, capital, assets or operations.

(k)The term “Law” shall mean any applicable statute, law, rule, regulation, ordinance, order, code, ruling, writ, injunction, decree or other official act of or by any Governmental Agency.

(l)The term “Net Acre” shall mean, as calculated separately with respect to each Lease described in Exhibit A-1 and listed in Part II of Schedule 2.2, (a) the number of gross acres in the lands covered by such Lease, multiplied by (b) the lessor’s undivided percentage interest in oil, gas or other minerals covered by such Lease in such lands, multiplied by (c) Seller’s Working Interest in such Lease; provided, that if items (b) and/or (c) vary as to different areas of such lands covered by such Lease, a separate calculation in accordance herewith shall be performed for each such area as if it were a separate Lease.

(m)The term “Net Revenue Interest” shall mean an interest (expressed as a percentage or decimal fraction) in and to all Hydrocarbons produced and saved from or attributable to a Lease or Well after giving effect to all Royalties, overriding Royalties, net profits interests, carried interests, and other Burdens payable out of production in favor of third parties.

(n)The term “Permitted Encumbrance” means (i) all Contracts, agreements, and other matters which are described on the Exhibits to this Agreement, (ii) lessors’ Royalties, overriding Royalties, reversionary interests, liens, Encumbrances, defects, irregularities, or similar burdens that do not operate to increase Seller’s Working Interest (without a proportionate increase in Seller’s Net Revenue Interest) with respect to any Subject Depth or reduce Seller’s Net Revenue Interest (without a proportionate reduction in Seller’s Working Interest) with respect to any Subject Depth in any of the Properties as such interests are set forth on Part I of Schedule 2.2, (iii) division orders and sales or processing contracts relating to production, (iv) all rights to consent by, required notices to, and filings with or other actions by Governmental Authorities, if any, in connection with the assignment of an interest in federal or state oil and gas leases or interests therein or related thereto that are customarily sought or obtained after delivery of such assignment, (v) the terms and conditions of all of the Leases and Contracts and agreements relating to the Properties, including, without limitation, exploration agreements, operating agreements, unitization, farmin or farmout agreements, and pooling and communitization agreements, gas sales contracts, processing agreements, and area of mutual interest agreements to which the Properties may be subject, including terms providing for the revision of interests by virtue of the election or default of a party or parties thereto, provided that such conditions or revisions do not operate to increase Seller’s Working Interest and/or reduce Seller’s Net Revenue Interest in any of the Properties with respect to any Subject Depth as such interests are shown on Part I of Schedule 2.2, (vi) undetermined or inchoate liens or charges constituting or securing the payment of expenses which were incurred incidental to maintenance, development, production or operation of the Properties or for the purpose of developing, producing or processing oil, gas or other Hydrocarbons therefrom or therein, (vii) any materialmans’, mechanics’, repairmans’, employees’, contractors’, operators’ or other similar liens, security interests or charges for liquidated amounts arising in the ordinary course of business incidental to construction, maintenance, development, production or operation of the Properties or the production or processing of oil, gas or other Hydrocarbons therefrom, that are not delinquent and that will be paid in the ordinary course of business or, if delinquent, that are being contested in good faith, (viii) any liens for taxes not yet delinquent or, if delinquent, that are being contested in good faith in the ordinary course of business, (ix) easements, rights-of-way, servitudes, permits, licenses, surface leases, and other rights in respect of surface operations, pipelines, or the like, and easements and rights-of-way, on, over, or in respect of the Properties, and all other liens, charges, Encumbrances, Contracts, agreements, instruments, and obligations provided that the same are customary in the industry and do not operate to interfere with the operation, value, or use of the Properties and which would be accepted by a reasonably prudent purchaser engaged in the business of owning and operating oil and gas properties, (x) any liens or security interests created by law or reserved in oil, gas and/or mineral leases for Royalty, bonus or rental or for compliance with the terms of the Leases, (xi) all agreements and obligations relating to Imbalances with respect to the production, transportation or processing of gas or calls or purchase options on oil or gas production that are set forth on Schedule 6.19, (xii) all obligations by virtue of a prepayment, advance payment or similar arrangement under any Contract for the sale of gas production, including by virtue of “take-or-pay” or similar provisions, to deliver gas

produced from or attributable to the Leases after the Effective Date without then or thereafter being entitled to receive full payment therefor, (xiii) rights reserved to or vested in any municipality or governmental, statutory, or public authority to control or regulate the Properties in any manner, and all applicable Laws, rules, and orders of any Governmental Agency, (xiv) conventional rights of reassignment requiring notice and/or the reassignment (or granting an opportunity to receive an assignment) of a leasehold interest to the holders of such reassignment rights prior to surrendering or releasing such leasehold interest that have not been triggered, (xv) all liens, charges, Encumbrances, Contracts, agreements, instruments, obligations, defects, irregularities and other matters affecting any Property which individually or in the aggregate are not such as to detract in any material respect from the value of, or interfere with the operation, value or use of such Property and which would be accepted by a reasonably prudent purchaser engaged in the business of owning and operating oil and gas properties, and (xvi) the liens and security interests listed on Schedule 4.2(d) attached hereto, provided such liens and security interests shall be released at Closing pursuant to Section 4.2(d) of this Agreement.

(o)The term “Person” shall mean any individual, firm, corporation, partnership, limited liability company, joint venture, association, trust, unincorporated organization, Governmental Agency or any other entity.

(p)The term “Royalties” shall mean royalties, overriding royalties, or other interest owners’ revenues or proceeds attributable to the sale of Hydrocarbons and payment in respect thereof, as applicable.

(q)The term “Seller Taxes” shall mean (i) all Income Taxes imposed by any applicable Law on Seller or its Affiliates and (ii) Asset Taxes allocable to Seller or its Affiliates pursuant to Section 18.1(a) (taking into account, and without duplication of, such Asset Taxes effectively borne by Seller or its Affiliates as a result of (A) the adjustments to the Purchase Price made pursuant to Section 2.4, Section 11.1 or Section 2.4(c), as applicable, and (B) any payments made from one Party to the other in respect of Asset Taxes pursuant to Section 18.1(a)(iii)), and (iii) any Taxes imposed on or with respect to the ownership or operation of the Excluded Assets or that are attributable to any asset or business of Seller that is not part of the Properties.

(r)The term “Subject Depth” shall mean with respect to any Well, the formation or formations currently being produced by such Well.

(s)The term “Taxes” shall mean, any taxes, assessments and other governmental charges in the nature of a tax imposed by any Governmental Agency, including but not limited to Asset Taxes, Income Taxes, profits, gross receipts, stamp, alternative or add-on minimum, ad valorem, real property, Personal Property, transfer, real property transfer, value added, sales, use, customs, duties, capital stock, franchise, excise, withholding, severance, production, estimated or other tax, including any interest, penalty or addition thereto.

(t)The term “Tax Return” shall mean any return, declaration, report, claim for refund, or information return or statement relating to Taxes, including any schedule or attachment thereto and any amendment thereof.

(u)A Property shall be deemed to have a "Title Defect" if Seller does not have Defensible Title thereto or other matter that causes Seller not to have Defensible Title in and to the Properties. Notwithstanding any other provision in this Agreement to the contrary, the following matters shall not be asserted as, and shall not constitute Title Defects: (i) defects that have been cured by possession under the applicable statutes of limitations, and (ii) defects based solely on lack of information in Seller’s files or solely on references to documents that are not in Seller’s files.

(v)The term “Title Defect Amount” means the amount by which the value of the Title Defect Property affected by such Title Defect is reduced as a result of the existence of such Title Defect, which shall be determined in accordance with the following:

(i)If the Title Defect is a lien or Encumbrance on Seller’s interest in a Property, the Title Defect Amount shall be the cost of removing such lien or encumbrance, provided, however, that such Title Defect Amount shall not exceed the value allocated to such Property on Schedule 2.2;

(ii)If the Title Defect results from Seller having a lesser Net Revenue Interest in a Title Defect Property than the Net Revenue Interest specified therefor in Part I of Schedule 2.2, the Title Defect Amount shall be equal to the product obtained by multiplying the portion of the Purchase Price Allocated to such Title Defect Property in Part I Schedule 2.2 by a fraction, the numerator of which is the reduction in the Net Revenue Interest and the denominator of which is the Net Revenue Interest specified for such Title Defect Property in Part I of Schedule 2.2;

(iii)If the Title Defect results from Seller having a greater Working Interest in a Title Defect Property than the Working Interest specified therefor in Part I Schedule 2.2, the Title Defect Amount shall be equal to the present value of the good faith estimate of the projected increase in the costs and expenses allocable to the Property after the Effective Date attributable to such increase in Seller’s Working Interest; provided, however, that no Title Defect Amount shall be allowed on account of and to the extent that an increase in Seller’s Working Interest in such Property has the effect of proportionately increasing Seller’s Net Revenue Interest therein;

(iv)If the Title Defect is that the actual Net Acres covered by a Lease is less than the number of Net Acres set forth in Part II of Scheduled 2.2 for such Lease, the Title Defect Amount shall be an amount equal to such difference in Net Acres multiplied by the value Allocated per Net Acre for such Lease set forth in Part II of Schedule 2.2;

(v)If the Title Defect results from any matter not described in Subsections 3.1(f)(i) through 3.1(f)(iv) above, the Title Defect Amount shall be an amount equal to the difference between: (i) the value of the affected Property without such Title Defect and (ii) the value of the affected Property with such Title Defect;

(vi)Notwithstanding (i) – (v), if Buyer and Seller agree on the Title Defect Amount, such amount shall be the Title Defect Amount; and

(vii)The Title Defect Amount with respect to a Property shall be determined without duplication of any costs or losses included in another Title Defect Amount hereunder.

(w)The term “Working Interest” shall mean, with respect to a Property, the percentage of interest in and to such Property that is burdened with the costs and expenses attributable to the exploration, maintenance, development and operation of a Property.

3.2Document Availability. Within three (3) Business Days following Buyer’s delivery of the Deposit to Seller, Seller shall make available copies of the Leases and the Records in its possession in their current form and format as maintained by Seller for Buyer to review, to the extent disclosure of any such document is not prohibited by confidentiality obligations or otherwise and would not result in the waiver of the attorney-client privilege or other legal privilege. The provisions of this Article III and the special warranty of title in the Assignment provide Buyer’s exclusive remedy with respect to any Title Defects or other deficiencies or defects in Seller’s title to the Properties. Seller’s title to all Properties shall be presumed

to be Defensible Title unless Buyer can prove through reasonable evidence submitted with a valid defect claim notice that satisfies the requirements set forth in Section 3.3 that Seller’s title to any Property is less than Defensible Title. Buyer shall provide reasonable evidence in proving the existence of each alleged Title Defect and Title Defect Amount with respect thereto.

3.3Buyer’s Title Review. Subject to the terms of Section 3.2 above, Buyer shall, at Buyer’s sole cost and expense, commence and diligently pursue examination of title to the Properties. Seller shall reasonably cooperate with Buyer and shall provide Buyer with access to all of the Leases and the Records in Seller’s possession in accordance with Section 3.2 above. From the Execution Date until 5:00 p.m. Denver, Colorado time on the date that is twenty (20) Business Days following the Execution Date (the “Due Diligence Period”), if Buyer determines that a Title Defect exists with respect to a Property, then Buyer, subject to Section 3.4, shall notify Seller prior to the expiration of the Due Diligence Period that it is instituting a claim pursuant to this Section 3.3 (a “Title Defect Notice”). To be effective, Buyer’s Title Defect Notice must include (a) a brief description of the matter constituting the asserted Title Defect, (b) the claimed Title Defect Amount attributable thereto, and (c) supporting documents reasonably necessary for Seller to verify the existence of such asserted Title Defect. Failure by Buyer to timely and/or properly assert a Title Defect shall be deemed an election by Buyer to waive such Title Defect and to accept and pay for the Property or interest therein affected by such uncured Title Defect and such uncured Title Defect shall thereupon be deemed a Permitted Encumbrance. To give Seller an opportunity to commence reviewing and curing Title Defects, Buyer shall periodically (but in no event less frequently than before 4:00 p.m. local time in Denver, Colorado on Thursday of each week during the Due Diligence Period) give Seller written notice of any Title Defect which Buyer determines exists following Buyer’s determination of the existence of same, which notice may be preliminary in nature and supplemented prior to the end of the Due Diligence Period. Buyer shall also, in good faith, furnish Seller periodically (but in no event less frequently than before 4:00 p.m. local time in Denver, Colorado on Thursday of each week during the Due Diligence Period) with written notice of any Seller Title Credit (as defined in Section 3.6) which is known by Buyer or is discovered by any of Buyer’s employees or representatives while conducting Buyer’s title review, due diligence or investigation with respect to the Properties.

3.4Seller’s Opportunity to Cure. Seller shall have five (5) Business Days after the expiration of the Due Diligence Period, if the Seller so elects but without obligation, to cure all or a portion of such asserted Title Defects to Buyer’s reasonable satisfaction. If Seller within such time fails to cure any Title Defect of which Buyer has given timely written notice as required above and Buyer has not and does not waive same in writing on or before the day immediately preceding the Closing Date, the Property affected by such uncured and unwaived Title Defect shall be a “Title Defect Property”.

3.5Title Defect Adjustments. Subject to Section 3.7, as Buyer’s sole and exclusive remedy with respect to Title Defects, Buyer shall be entitled to reduce the Purchase Price in accordance with Section 2.4 by the aggregate Title Defect Amounts attributable to such Title Defect Property; provided, however, if the Title Defect Amount with respect to all Title Defects with respect to a single Title Defect Property is, in the aggregate, fifteen thousand dollars ($15,000) (the “Title Defect Threshold”) or less, then the Title Defect Amount with respect to such Title Defect Property shall be deemed to be zero.

3.6Seller Title Credit. “Seller Title Credit” shall mean, with respect to a Property, the amount by which the value of such Property is enhanced by virtue of (a) Seller having a greater Net Revenue Interest in such Property (without a proportionate increase in Seller’s Working Interest) than the Net Revenue Interest specified therefor in Part I of Schedule 2.2, (b) Seller having a lesser Working Interest in such Property (without a proportionate decrease in Seller’s Net Revenue Interest) than the Working Interest specified therefor in Part I of Schedule 2.2, or (c) with respect to each Lease described in Part II of Schedule 2.2, Seller having a greater number of Net Acres than the number of Net Acres specified therefor in Part II of Schedule 2.2. The amount of Seller Title Credits shall be determined as follows:

(i)If the Seller Title Credit results from Seller having a greater Net Revenue Interest in such Property than the Net Revenue Interest specified therefor in Part I of Schedule 2.2, the Seller Title Credit shall be equal to the product obtained by multiplying the portion of the Purchase Price Allocated to such Property in Part I of Schedule 2.2 by a fraction, the numerator of which is the increase in the Net Revenue Interest and the denominator of which is the Net Revenue Interest specified for such Property in Part I of Schedule 2.2;

(ii)If the Seller Title Credit results from Seller having a lesser Working Interest in a Property than the Working Interest specified therefor in Part I of Schedule 2.2, the Seller Title Credit shall be equal to the present value of the good faith estimate of the projected decrease in the costs and expenses allocable to the Property after the Effective Date that is reasonably agreed to by Buyer and Seller; provided, however, that no Seller Title Credit shall be allowed on account of and to the extent that a decrease in Seller’s Working Interest in such Property has the effect of proportionately reducing Seller’s Net Revenue Interest therein;

(iii)If the Seller Title Credit is that the actual Net Acres covered by a Property that is a Lease is greater than the number of Net Acres set forth in Part II of Schedule 2.2 for such Lease, the Title Defect Amount shall be an amount equal to such difference in Net Acres multiplied by the value allocated per Net Acre for such Lease set forth in Part II of Schedule 2.2; and

(iv)if a Property has no Allocated Value, then such Property shall have no Seller Title Credit.

3.7Exclusion of Title Defect Properties. On or before the Closing Date, Seller may with respect to any Title Defect Property, elect to retain and exclude such Title Defect Property from the Properties to be conveyed by Seller to Buyer pursuant to the terms hereof so long as the Purchase Price is reduced by the portion of the Purchase Price Allocated to such Property in Schedule 2.2. In the event Seller exercises its right under pursuant to the foregoing sentence with respect to a Title Defect Property, said Title Defect Property, together with a pro rata share of all incidental rights, Hydrocarbons and other assets attributable or appurtenant thereto, shall be retained by Seller and excluded from the Properties which are conveyed by Seller to Buyer.

3.8Subsequent Closings. In the event that Seller (i) elects to attempt to cure any Title Defect(s) during the time period provided for in Section 3.4 and (ii) elects to exercise its right under Section 3.7 with respect to a Title Defect Property, Seller may elect to continue such attempt to cure such Title Defect(s) until the Final Settlement Date. In the event that Seller cures all or a portion of such asserted Title Defect(s) to Buyer’s reasonable satisfaction prior to the Final Settlement Date, then (x) Seller shall convey to Buyer the applicable Property or Properties previously withheld from the Closing on account of such Title Defects, (y) the Parties will execute and deliver all applicable instruments required to be delivered at Closing pursuant to Article IV, and (iii) Buyer shall pay the sum by which the Purchase Price was reduced at Closing on account of such Property or Properties that are the subject of such subsequent closing.

3.9No Duplication. Notwithstanding anything herein provided to the contrary, if a Title Defect results from any matter which could also result in the breach of any representation or warranty of Seller set forth in Article VI hereof, then Buyer shall only be entitled to assert such matter as a Title Defect pursuant to this Article III and shall be precluded from also asserting such matter as the basis of the breach of any such representation or warranty.

3.10Title Dispute Resolution. Seller and Buyer shall attempt to agree in writing on matters regarding (i) all Title Defects, and (ii) the adequacy of any curative materials provided by Seller to cure an

alleged Title Defect (collectively, the “Disputed Title Matters”) prior to Closing (or, if Seller elects to attempt to cure pursuant to Section 3.4 or Section 3.8, then prior to the end of the period for such cure). If Seller and Buyer are unable to agree in writing by Closing (or by the Final Settlement Date if Seller elects to attempt to cure a Title Defect after Closing), the Disputed Title Matters shall be exclusively and finally resolved pursuant to this Section 3.10. There shall be a single arbitrator, who shall be a title attorney or consultant with at least fifteen (15) years’ experience in oil and gas titles involving properties in the regional area in which the Title Defect Properties are located, as selected by mutual written agreement of Buyer and Seller within fifteen (15) days after the Closing Date or by the Final Settlement Date, as applicable (the “Title Arbitrator”). If the Parties cannot agree on a Title Arbitrator within fifteen (15) days after the Closing Date, each Party will appoint a Title Arbitrator within ten (10) days thereafter, the two Title Arbitrators so appointed will appoint a third Title Arbitrator within ten (10) days after the second Title Arbitrator is appointed, and such third Title Arbitrator shall be the sole Title Arbitrator to determine the dispute. The Title Arbitrator’s determination shall be made within thirty (30) days after submission of the matters in and shall be final and binding upon the Parties, without right of appeal. In making its determination, the Title Arbitrator may consider such other matters as in the opinion of the Title Arbitrator are necessary or helpful to make a proper determination; provided, however, that the Title Arbitrator shall be limited to awarding only one or the other of the two proposed settlement amounts. The Title Arbitrator shall act as an expert for the limited purpose of determining the specific Disputed Title Matter submitted by either Party and may not award damages, interest or penalties to either Party with respect to any matter. The costs of the Title Arbitrator shall be borne equally between the Parties. To the extent that the award of the Title Arbitrator with respect to any Title Defect Amount or Title Benefit Amount is not taken into account as an adjustment to the Purchase Price pursuant to Section 2.4, then, within ten (10) days after the Title Arbitrator delivers written notice to Buyer and Seller of his award with respect to a Title Defect Amount or Title Benefit Amount, the Parties shall account to each other in accordance with the terms of such award. Nothing herein shall operate to cause Closing to be delayed on account of any unresolved Disputed Title Matter arbitration conducted pursuant to this Section 3.10, and to the extent any adjustments are not agreed upon by the Parties in writing as of Closing, the Purchase Price shall not be adjusted therefor at Closing and subsequent adjustments to the Purchase Price, if any, will be made pursuant to Section 2.4 or this Section 3.10.

ARTICLE IV

CLOSING

4.1Closing. The “Closing” of the transactions contemplated hereby shall take place by electronic delivery of documents (by “portable document format,” email, DocuSign or other form of electronic communication), all of which will be deemed to be originals; provided, any original documents or signatures required or requested in connection with the Closing will be delivered to the offices of Buyer as set forth in Section 19.3 on or before the date that not later than three (3) Business Days following the Closing Date or such other date as Seller and Buyer may mutually agree. The date on which Closing actually occurs shall be on or before Twenty-Five (25) Business Days following the Execution Date or such other date as Seller and Buyer may mutually agree (the “Closing Date”).

4.2Seller’s Closing Obligations. At Closing, Seller shall execute and deliver, or cause to be executed and delivered, to Buyer the following:

(a)an Assignment and Bill of Sale (the “Assignment”), from Seller, effective as of the Effective Date and substantially in the form of Exhibit B attached hereto;

(b)the Preliminary Settlement Statement;

(c)a certificate, dated as of the Closing Date, executed by a duly authorized officer of Seller, to the effect that the representations and warranties of Seller contained in Article VI shall be true

and correct in all respects on and as of the Closing Date as though made on and as of the Closing Date (“Seller’s Certificate”);

(d)releases, in form reasonably satisfactory to Buyer, of the liens and security interests described in Schedule 4.2(d);

(e)the Records and any letters in lieu of division and transfer orders relating to the Properties in form reasonably necessary to reflect the conveyances contemplated hereby; and.

(f)a duly executed certification from Seller that it is not a foreign Person within the meaning set forth in Treasury Regulation Section 1.1445-2(b)(2)(iii)(A); it being understood that notwithstanding anything to the contrary contained herein, if Seller fails to provide Buyer with such certification, Buyer shall be entitled to withhold the requisite amount from the Purchase Price in accordance with Section 1445 of the Internal Revenue Code and the applicable Treasury Regulations.

4.3Buyer’s Closing Obligations. At Closing, Buyer shall execute (as applicable) and deliver, or cause to be executed and delivered, to Seller the following:

(a)the Assignment, effective as of the Effective Date;

(b)the Preliminary Settlement Statement;

(c)the Adjusted Purchase Price pursuant to Section 2.4, shown on the Preliminary Settlement Statement, by wire transfer in immediately available funds, according to the written wire instructions provided by Seller; and

(d)a certificate, dated as of the Closing Date, executed by a duly authorized officer of Buyer, to the effect that the representations and warranties of Buyer contained in Article IV shall be true and correct in all material respects on and as of the Closing Date as though made on and as of the Closing Date.

4.4Application of Deposit. At Closing, Seller shall retain the entire Deposit as additional consideration for the transactions contemplated by this Agreement and the Deposit shall be applied to the Adjusted Purchase Price.

4.5Records. In addition to the obligations set forth under Section 4.2, but notwithstanding anything herein to the contrary, no later than twenty (20) Business Days after the Closing Date, Seller shall make available to Buyer the Records in its possession in their current form and format as maintained by Seller as of the Effective Time, for pickup from Seller’s offices during normal business hours; provided that Seller may retain (x) written or electronic copies of the Records and (y) originals of Records relating to Asset Taxes and provide Buyer with copies thereof.

ARTICLE V

CONDITION AND FITNESS OF THE PROPERTIES

5.1Condition and Fitness of the Properties. IT IS THE EXPLICIT INTENT AND UNDERSTANDING OF SELLER AND BUYER THAT, EXCEPT FOR THE REPRESENTATIONS AND WARRANTIES OF SELLER IN THIS AGREEMENT AND EXCEPT FOR THE SPECIAL WARRANTY OF TITLE GIVEN IN THE ASSIGNMENT, SELLER IS NOT MAKING ANY REPRESENTATION OR WARRANTY WHATSOEVER—EXPRESS, IMPLIED, STATUTORY, OR OTHERWISE—REGARDING THE PROPERTIES AND BUYER SHALL TAKE THE PROPERTIES "AS IS" AND "WHERE IS" AND "WITH ALL FAULTS". WITHOUT

LIMITING THE GENERALITY OF THE IMMEDIATELY PRECEDING SENTENCES, SELLER HEREBY EXPRESSLY DISCLAIMS AND NEGATES ANY REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, AT COMMON LAW, BY STATUTE, OR OTHERWISE, RELATING TO: i. THE CONDITION OF THE PROPERTIES (INCLUDING, WITHOUT LIMITATION, ANY IMPLIED OR EXPRESS WARRANTY OF QUALITY, MERCHANTABILITY, OR FITNESS FOR A PARTICULAR PURPOSE, OR OF CONFORMITY TO MODELS OR SAMPLES OF MATERIALS, OR THE PRESENCE OR ABSENCE OF ANY HAZARDOUS MATERIALS IN OR ON, OR DISPOSED OF OR DISCHARGED FROM, THE PROPERTIES), ii. THE PROPERTIES’ PAST, PRESENT OR FUTURE COMPLIANCE WITH ENVIRONMENTAL LAW, OR iii. ANY INFRINGEMENT BY SELLER OR ANY OF ITS RESPECTIVE AFFILIATES OF ANY PATENT OR PROPRIETARY RIGHT OF ANY THIRD PARTY, IT BEING THE INTENTION OF SELLER AND BUYER THAT THE PROPERTIES SHALL BE ACCEPTED BY BUYER IN THEIR PRESENT CONDITION AND STATE OF REPAIR.

5.2Disclaimer of Warranties. EXCEPT FOR THE REPRESENTATIONS AND WARRANTIES OF SELLER IN THIS AGREEMENT AND THE SPECIAL WARRANTY OF TITLE GIVEN IN THE ASSIGNMENT, SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY—EXPRESS, IMPLIED, STATUTORY, OR OTHERWISE— AS TO: i. TITLE TO ANY OF THE PROPERTIES; ii. THE CONTENTS, CHARACTER, OR NATURE OF ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY ENGINEERING, GEOLOGICAL, OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE PROPERTIES; iii. THE QUANTITY, QUALITY, OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE PROPERTIES; iv. ANY ESTIMATES OF THE VALUE OF THE PROPERTIES OR FUTURE REVENUES GENERATED BY THE PROPERTIES; v. THE PRODUCTION OF HYDROCARBONS FROM THE PROPERTIES; vi. THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN, OR MARKETABILITY OF THE PROPERTIES, AND vi. THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN, OR MARKETABILITY OF THE PROPERTIES, INCLUDING BUT NOT LIMITED TO THEIR COMPLIANCE WITH ENVIRONMENTAL LAWS OR OTHER LAWS, RULES, OR REGULATIONS; vii. THE CONTENT, CHARACTER, OR NATURE OF ANY REPORTS, BROCHURES, CHARTS, OR STATEMENTS PREPARED BY THIRD PARTIES; AND viii. THE ACCURACY, COMPLETENESS, PRESENCE OR ABSENCE OF THE RECORDS, THE CONTRACTS, OR ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE OR COMMUNICATED TO BUYER OR ITS AFFILIATES, OR ITS EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES, OR ADVISORS IN CONNECTION WITH THIS AGREEMENT.

ARTICLE VI

SELLER’S REPRESENTATIONS AND WARRANTIES

Seller makes the following representations and warranties to Buyer as of the Effective Date and as of the Execution Date. As used in this Article VI, “to Seller’s knowledge”, or similar terms, means the actual knowledge (with such reasonable investigation as might be expected from a prudent non-operator in the areas where the Properties are located, it being understood that a prudent non-operator would not be required to inquire with any third-party operator about the accuracy or completeness of the representations and warranties set forth in this Article VI) of Robert Shubin and Ed Mellor.

6.1Status. Seller is duly organized, validly existing and in good standing under the Laws of the jurisdiction of its organization. Seller is duly licensed or qualified to do business and is in good standing

in each jurisdiction in which the ownership of the Properties makes such licensing or qualification necessary.

6.2Power. Seller has all requisite power and authority to carry on its business as presently conducted. The execution and delivery of this Agreement does not, and the fulfillment of and compliance with the terms and conditions hereof will not violate, or be in conflict with, any material provision of Seller’s governing documents, or any material provision of any agreement or instrument to which Seller is a party or by which it is bound, or any judgment, decree, order, statute, rule or regulation applicable to Seller.

6.3Authorization and Enforceability. This Agreement constitutes Seller’s legal, valid and binding obligation, enforceable in accordance with its terms, subject, however, to the effects of bankruptcy, insolvency, reorganization, moratorium and other laws for the protection of creditors, as well as to general principles of equity, regardless of whether such enforceability is considered in a proceeding in equity or at law.

6.4Liability for Brokers’ Fees. Seller has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Buyer shall have any responsibility whatsoever.

6.5No Bankruptcy. There are no bankruptcy, reorganization, liquidation, or receivership proceedings pending, being contemplated by or, threatened against Seller.

6.6Litigation. There is no action, suit, proceeding, claim or investigation by any person, entity, administrative agency or Governmental Agency pending or threatened against Seller with respect to the Properties; nor is Seller in default under any order, writ, injunction, or decree of any court or federal, state, municipal or other governmental agency with respect to the Properties except as disclosed on Schedule 6.6.

6.7Compliance with Laws. Seller’s ownership of the Leases and Wells has been in conformity with all applicable laws, rules, regulations, guidelines and orders of all Governmental Authorities having jurisdiction, relating to the Lease and the Wells.

6.8Title to Properties. Neither Seller nor its Affiliates has sold, transferred, or assigned any of the Properties or provided any Person rights to ownership of the Seller’s Properties.

6.9Conduct in Ordinary Course and Absence of Certain Changes. Except as listed in Schedule 6.9, since the Effective Time, Seller has conducted its business in the ordinary course of business consistent with past practice in all material respects.

6.10Consents. Except (i) as set forth on Schedule 6.10, and (ii) for consents and approvals from Governmental Authorities for the assignment of the Properties to Buyer that are customarily obtained after the assignment of properties similar to the Properties, there are no restrictions on assignment, including requirements for consents from third parties to any assignment (in each case), that Seller is required to obtain in connection with the transfer of the Properties by Seller to Buyer or the consummation of the transactions contemplated by this Agreement by Seller (each, a “Consent”).

6.11No Conflicts. The execution, delivery and performance by Seller of this Agreement and the transaction documents to which it is a party and the consummation of the transactions contemplated herein and therein will not conflict with or result in a breach of any provisions of the organizational documents of Seller, or violate any Law applicable to Seller or any of the Properties.

6.12Operation of Properties. Except as set forth on Schedule 6.12, to Seller’s knowledge, all Wells, Leases, and other Properties operated by Seller have been drilled, completed, operated, and produced in accordance with generally accepted oil and gas field practices and in compliance in all respects with all Leases, pooling and unit agreements, joint operating agreements (if applicable), and Laws. Except as set forth on Schedule 6.12, Seller has not received any notices or demands from any Governmental Agency to plug or abandon any Wells. To Seller’s knowledge, all of the Leases are in full force and effect, and Seller has not received any written notice of default or breach under any of the Leases which default, or breach has not been cured or remedied to the satisfaction of the applicable lessor.

6.13Environmental Laws. Except as set forth on Schedule 6.13:

(a)To Seller’s knowledge, the Properties are in compliance with applicable Environmental Laws.

(b)Seller has not received from any Governmental Agency any written or electronic notice or claim of violation of, alleged violation of, or non-compliance with, any Environmental Law with respect to the Properties other than notices with respect to matters that have been resolved to the satisfaction of any relevant Governmental Agency or for which Seller has no further material obligations outstanding.

(c)To Seller’s knowledge, none of the Properties are subject to any unfulfilled orders, consent decrees or judgments of any Governmental Agency; and

(d)Seller has not received written notice from or given notice to any Person of any release or disposal of any Hazardous Substances relating to the Properties that could (i) interfere with or prevent compliance by Seller or Buyer with any Environmental Laws or the term of any permit issued pursuant thereto, or (ii) give rise to or result in any liability of Seller’s or Buyer to any Person.

6.14Liens. Except for Encumbrances that will be released on or before Closing, there are no contractual Encumbrances on the Properties granted by Seller or its Affiliates to secure indebtedness for borrowed money. The Properties will be delivered to Buyer free and clear of all Encumbrances except for Permitted Encumbrances.

6.15Permits. Seller possesses all permits, licenses, certificates, consents, approvals, and other authorizations required of Seller by any Governmental Agency (for purposes of this Section 6.15 collectively, “Permits”), and has made all filings with any Governmental Agency required to be made in the two (2) years preceding the Execution Date, in each case that are required for Seller’s ownership and operation of the Properties.

6.16Material Contracts. Schedule 6.16 sets forth, as of the Execution Date, all Contracts of the type described below (collectively, the “Material Contracts”):

(i)any Contract that can reasonably be expected to result in aggregate payments by Seller of more than $20,000 during the remainder of the current or any subsequent calendar year (based solely on the terms thereof and current volumes, without regard to any expected increase in volumes or revenues);

(ii)any Hydrocarbon purchase and sale, transportation, gathering, treating, processing or similar Applicable Contract that is not terminable without penalty upon ninety (90) days’ or less notice;

(iii)any indenture, mortgage, loan, credit or sale-leaseback or similar Applicable Contract that is secured with mortgages or liens on the Properties, in each case that will not be released or terminated on or before Closing;

(iv)any Contract that constitutes a lease under which Seller is the lessor or the lessee of Personal Property which lease (A) cannot be terminated by Seller without penalty upon ninety (90) days’ or less notice and (B) involves an annual base rental by Seller of more than $50,000 (without regard to any increase in price);

(v)any farmin or farmout agreement, participation agreement, exploration agreement, development agreement, joint operating agreement, unit agreement or any similar Contract where, in each case, the primary obligation thereunder has not been fully performed;

(vi)any Contract between Seller and any Affiliate of Seller that is binding on the Properties and will not be terminated prior to or as of the Closing;

(vii)any Contract that provides for an area of mutual interest; and

(viii)any Contract that contains a non-compete agreement or otherwise purports to restrict, limit or prohibit the manner in which, or the locations in which, Seller may conduct its business.

(b)Except as set forth on Schedule 6.16, there exists no breach or default under any Material Contract by Seller or by any other Person that is a party to such Material Contract, and no event has occurred that with notice or lapse of time or both would constitute any material default under any such Material Contract by Seller or any other Person who is a party to such Material Contract. Seller has made available for Buyer’s review true and complete copies of each Material Contract and any and all amendments thereto.

6.17Preferential Purchase Rights. Except as set forth on Schedule 6.17, there are no preferential purchase rights, rights of first refusal or other similar rights that are applicable to the transfer of the Properties in connection with the transactions contemplated hereby (each a “Preferential Purchase Right”).

6.18Royalties. To Seller’s knowledge, all Royalties and/or other Burdens with respect to Seller’s ownership of the Properties have been paid on Seller’s behalf.

6.19Imbalances. Except as set forth on Schedule 6.19, there are no Imbalances associated with the Properties as of the Effective Date. There are no agreements or obligations relating to Imbalances.

6.20Current Commitments. Schedule 6.20 sets forth, as of the Execution Date, each authority for expenditures for an amount greater than $20,000 (net to Seller’s interest in the Properties) (collectively, the “AFEs”) relating to the Properties to drill or rework wells or for other capital expenditures for which all of the activities anticipated in such AFEs or commitments have not been completed by the Execution Date.

6.21Taxes. Except as set forth on Schedule 6.21, all Taxes due and owing by Seller have been, or will be, timely paid. No extensions or waivers of statues of limitations have been given or requested with respect to any Taxes of Seller. All Tax Returns required to be filed by Seller for any tax periods prior to Closing have been, or will be, timely filed. Such Tax Returns are, or will be, true, complete, and correct in all respects.

6.22Payments for Production. Seller is not obligated by virtue of a take-or-pay payment, advance payment or other similar payment (other than gas balancing agreements) to deliver Hydrocarbons, or proceeds from the sale thereof, attributable to Seller’s interest in the Properties at some future time without receiving full payment therefor at or after the time of delivery.

6.23Payout Status. Schedule 6.23 sets forth the “payout” balance, as of the dates set forth on such Schedule, for each Well, subject to a reversion or other adjustment at some level of cost recovery or payout (or passage of time or other event other than termination of a Lease by its terms).

6.24Affiliate Interests. No Affiliate of Seller has any interest in the Properties or any right, title or interest to any assets or properties that would otherwise be included in the definition of “Properties” hereunder if such assets or interests were owned by Seller.

6.25Equipment. To Seller’s knowledge, the Personal Property included in the Properties, taken as a whole, has not been damaged as to render such tangible Personal Property inadequate for normal operation of the Properties consistent with standard industry practice in the areas in which they are operated and with operations as currently conducted, ordinary wear and tear excepted.

6.26Non-Consent Operations. Except as set forth on Schedule 6.26, no operations are being conducted or have been conducted on the Properties with respect to which Seller has elected to be a non-consenting party under the applicable operating agreement and with respect to which all of Seller’s rights have not yet reverted.

6.27Surface Access. To Seller’s knowledge, there are no surface use or access agreements currently in force that will interfere with operations on the Leases. To Seller’s knowledge, Seller has a reasonable right of ingress and egress to all of the Leases and Wells, subject to compliance with any applicable surface use restrictions and obtaining any required consents of third parties, including third party operators of the Properties.

ARTICLE VII

BUYER’S REPRESENTATIONS AND WARRANTIES

Buyer makes the following representations and warranties to Seller as of the Execution Date:

7.1Organization and Standing. Buyer is a corporation, duly organized, validly existing and in good standing under the laws of the State of Nevada and is duly qualified to carry on its business in the State of Oklahoma.

7.2Power. Buyer has all requisite power and authority to carry on its business as presently conducted. The execution and delivery of this Agreement does not, and the fulfillment of and compliance with the terms and conditions hereof will not, as of the Closing Date, violate, or be in conflict with, any material provision of Buyer’s governing documents, or any material provision of any agreement or instrument to which Buyer is a party or by which it is bound, or any judgment, decree, order, statute, rule or regulation applicable to Buyer.

7.3Authorization and Enforceability. This Agreement constitutes Buyer’s legal, valid and binding obligation, enforceable in accordance with its terms, subject, however, to the effects of bankruptcy, insolvency, reorganization, moratorium and other laws for the protection of creditors, as well as to general principles of equity, regardless of whether such enforceability is considered in a proceeding in equity or at Law.

7.4Liability for Brokers’ Fees. Buyer has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Seller shall have any responsibility whatsoever.

7.5No Bankruptcy. There are no bankruptcy proceedings pending, being contemplated by or, threatened against Buyer.

7.6Litigation. There is no action, suit, proceeding, claim or investigation by any person, entity, administrative agency or Governmental Agency pending or, to the knowledge of Buyer, threatened against Buyer that impedes or is likely to impede Buyer’s ability to consummate the transaction contemplated by this Agreement and to assume the liabilities to be assumed by Buyer under this Agreement except as disclosed on Schedule 7.6.

7.7Funds. Buyer has sufficient funds available to enable Buyer to consummate the transactions contemplated hereby and to pay all related fees and expenses of Buyer.

ARTICLE VIII

ADDITIONAL COVENANTS

8.1Conduct of Business Pending Closing. From the Execution Date until the Closing Date, except as disclosed on Schedule 8.1 or as otherwise consented to by Buyer in writing (which consent or approval shall not be unreasonably withheld, conditioned or delayed), Seller covenants and agrees that:

(a)Seller shall not sell, transfer, assign, convey, farmout, release, abandon or otherwise dispose of any Properties, or enter into any transaction the effect of which would be to cause Seller’s ownership interest in any of the Properties to be altered from Seller’s ownership interest as of the Effective Date, other than Hydrocarbons produced, saved and sold in the ordinary course of business;

(b)Seller shall not grant a lien on or a security interest in any Properties (other than a Permitted Encumbrance); and

(c)Seller shall not elect to not participate, or be non-consent, in the drilling of any new well or other new operations on the Properties, without the advance written consent of Buyer, which consent or non-consent must be given by Buyer within the lesser of (x) ten (10) days of Buyer’s receipt of the notice from Seller or (y) one-half (½) of the applicable notice period within which Seller is contractually obligated to respond to third parties to avoid a deemed election by Seller regarding such operation, as specified in Seller’s notice to Buyer requesting such consent; provided that, failure by Buyer to respond within the aforesaid applicable period shall constitute Buyer’s consent to Seller’s election to not participate in such well or other operation.

(d)Except (i) as set forth on Schedule 8.1(d), (ii) for the operations covered by the AFEs and other capital commitments described on Schedule 6.20, (iii) for actions taken in connection with emergency situations affecting life or to maintain a lease or as required by Law or a Governmental Agency or any Material Contract and (iv) as expressly contemplated by this Agreement or as expressly consented to in writing by Buyer (which consent shall not be unreasonably delayed, withheld or conditioned), Seller shall, from and after the Execution Date until Closing:

(i)own and maintain the Properties in an ordinary manner consistent with past practice;

(ii)not propose any operation reasonably expected to cost Seller in excess of $20,000 (net to Seller’s interest in the Properties);

(iii)notify Buyer before Seller agrees to participate in any operation proposed by a third party that is reasonably expected to cost Seller in excess of $20,000 (net to Seller’s interest in the Properties);

(iv)except in the ordinary course of business, not enter into a Contract that, if entered into on or prior to the Execution Date, would be required to be listed on Schedule 6.16, or materially amend or change the terms of or terminate any Material Contract;

(v)not transfer, sell, mortgage, pledge or dispose of any portion of the Properties other than (A) the sale or disposal of Hydrocarbons in the ordinary course of business or (B) items constituting Permitted Encumbrances;

(vi)provide Buyer with copies of any and all material correspondence received from any Governmental Agency with respect to the Properties within five (5) days of the receipt thereof;

(vii)not voluntarily abandon any of the Properties other than as required pursuant to the terms of a Lease or applicable Law;

(viii)maintain its existing insurance policies relating to the Properties in such amounts and with such deductibles as are currently maintained by Seller;

(ix)not settle or compromise any proceeding relating to the Properties, other than settlements or compromises (A) of matters for which Seller is liable for under the terms of this Agreement or (B) that involve only the payment of monetary damages not in excess of $20,000 individually or $100,000 in the aggregate (excluding amounts to be paid under insurance policies);

(x)not commit to do any of the foregoing in clauses (ii), (iv), (v), (vii) or (ix);

(xi)obtain all Preferential Purchase Rights and other Consents required by third parties, Governmental Agency and others as may be required to consummate the transaction;

(xii)except with respect to any Excluded Assets, maintain in effect all Permits as may be necessary for Seller or its Affiliates to own and operate the Properties; and

(xiii)give prompt written notice to Buyer of any damage to or destruction of any of the Properties.

ARTICLE IX

CONDITIONS PRECEDENT TO CLOSING

9.1Seller’s Conditions. The obligations of Seller at Closing are subject to, at the option of Seller, the satisfaction or waiver at or prior to the Closing Date of the following conditions precedent:

(a)All representations and warranties of Buyer contained in this Agreement shall be true and correct in all material respects on and as of the Closing Date, and Buyer shall have performed and satisfied all covenants and agreements required by this Agreement to be performed and satisfied by Buyer at or prior to the Closing Date in all material respects.

(b)No order has been entered by any court or Governmental Agency having jurisdiction over the Parties or the subject matter of this Agreement that restrains or prohibits the purchase and sale contemplated by this Agreement and that remains in effect at Closing.

(c)Buyer shall have performed or complied with all obligations, agreements and covenants contained in this Agreement as to which performance or compliance by Buyer is required prior to or on the Closing Date.

(d)No Governmental Agency shall have enacted, issued, promulgated, enforced or entered any statute, rule, regulation, injunction or other order which is in effect and has the effect of making the transactions contemplated by this Agreement illegal or otherwise restraining or prohibiting consummation of such transactions.

9.2Buyer’s Conditions. The obligations of Buyer at Closing are subject to, at the option the Buyer, the satisfaction or waiver at or prior to the Closing Date of the following conditions precedent:

(a)All representations and warranties of the Seller contained in this Agreement shall be true and correct in all material respects on and as of the Closing Date with the same force and effect as though such representations and warranties had been made or given on and as of the Closing Date, and Seller shall have performed and satisfied all covenants and agreements required by this Agreement to be performed and satisfied by Seller at or prior to the Closing Date in all material respects.

(c)Seller shall have performed or complied with all obligations, agreements and covenants contained in this Agreement as to which performance or compliance by Seller is required prior to or on the Closing Date.

(e)The sum of (a) all Title Defect Amounts for all actual Title Defects that are properly asserted by Buyer prior to the end of the Due Diligence Period pursuant to Section 3.3, that individually exceed the Individual Title Defect Threshold (excluding any Title Defect Amounts with respect to any Properties excluded from the transactions contemplated by this Agreement in accordance with this Agreement), plus (b) the Allocated Value of all Properties excluded from the transactions contemplated by this Agreement on account of Environmental Defects pursuant to Section 14.1(c)(ii), plus (c) the losses to the Properties in respect of all Casualty Losses that occur between the Execution Date and the Closing as determined in accordance with Section 17.1, plus (d) the Allocated Value of all Properties excluded from the transactions contemplated hereby on account of Hard Consents and Preferential Purchase Rights pursuant to Section 16.1 and Section 16.2, as applicable, shall be in the aggregate less than twenty percent (20%) of the Purchase Price.

9.3Closing Deliverables. Seller shall have delivered (or be ready, willing and able to deliver at Closing) to Buyer the documents and other items required to be delivered by Seller under Section 4.2. Buyer shall have delivered (or be ready, willing and able to deliver at Closing) to Seller the documents and other items required to be delivered by Buyer under Section 4.3.

ARTICLE X

TERMINATION

10.1Termination. This Agreement may be terminated in accordance with the following provisions:

(a)By mutual consent of Buyer and Seller;

(b)By either Party in accordance with Section 17;

(c)By Seller if the conditions set forth in Section 9.1 are not satisfied on or before March 11, 2024, through no fault of Seller, or waived by Seller in writing, as of Closing; or

(d)By Buyer if the conditions set forth in Section 9.2 are not satisfied on or before March 11, 2024, through no fault of Buyer, or waived by Buyer in writing, as of Closing.

10.2Effect of Termination.

(a)Buyer’s Default. If Closing does not occur because the Buyer wrongfully, willfully or deliberately acts or fails to act, and such act or failure to act constitutes in and of itself a material breach of any covenant set forth in this Agreement, including failure to tender performance at Closing or otherwise materially breached this Agreement prior to Closing, and if Seller is not in material breach of this Agreement and is ready, willing and able to close the transactions contemplated by this Agreement, Seller, after first giving Buyer prior written notice of such failure to tender performance or material breach of this Agreement and such failure or material breach continues for a period of five (5) Business Days, Seller may terminate this Agreement and retain the Deposit, including any interest and other amount earned thereon, as liquidated damages. Seller and Buyer agree upon the Deposit as liquidated damages due to the difficulty and inconvenience of measuring actual damages and the uncertainty thereof, and Seller and Buyer agree that such amount is a reasonable estimate of Seller’s loss in the event of any such failure by Buyer and is not a penalty. Buyer’s failure to close shall not be considered wrongful if Buyer’s conditions under Section 9.2 are not satisfied through no fault of Buyer and are not waived by Buyer. For the avoidance of doubt, if Buyer’s failure to close is not considered wrongful pursuant to the foregoing, then Buyer shall be entitled to a full refund of the Deposit (including any interest and other amount earned thereon) which shall be paid to Buyer by Seller within five (5) Business Days of the termination date.

(b)Seller’s Default. If Closing does not occur because Seller wrongfully, willfully or deliberately acts or fails to act, and such act or failure to act constitutes in and of itself a material breach of any covenant set forth in this Agreement, in including failure to tender performance at Closing or otherwise materially breached this Agreement prior to Closing, and if Buyer is not in material breach of this Agreement and is ready, willing and able to close the transactions contemplated by this Agreement, Buyer shall be entitled, to a full refund of the Deposit (including any interest and other amount earned thereon) and to seek all rights and remedies available at Law or in equity for Seller’s wrongful breach, including but not limited to enforcing specific performance. Seller’s failure to close shall not be considered wrongful pursuant to the foregoing, if Seller’s conditions under Section 9.1 are not satisfied through no fault of Seller and are not waived by Seller. Refund of the Deposit shall be paid to Buyer by Seller within five (5) Business Days of the termination date.

(c)Other Termination. If Seller and Buyer mutually agree to terminate this Agreement, each Party shall release the other Party from any and all liability for termination of this Agreement and the Deposit (including any interest and other amount earned thereon) shall be paid to Buyer by Seller within five (5) Business Days of the termination date.

(d)Intentionally Omitted.

ARTICLE XI

SETTLEMENT STATEMENT

11.1Settlement Statement. No fewer than five (5) Business Days prior to Closing, Seller shall prepare and deliver to Buyer and Seller a draft settlement statement (the “Preliminary Settlement Statement”) providing for all calculations and adjustments to the Purchase Price and all other amounts payable or credited to the applicable Parties as provided in this Agreement pursuant to Section 2.4. The Parties shall, on or before Closing agree on the provisions of a settlement statement to be executed by them (the “Settlement Statement”) at Closing. Within three (3) Business Days after receipt of the Preliminary Settlement Statement, Buyer shall deliver to Seller a written report containing all changes that Buyer proposes to be made to the Preliminary Settlement Statement together with the explanation therefor and the supporting documents thereof. The Parties shall in good faith attempt to agree in writing on the Preliminary Settlement Statement as soon as possible after Seller’s receipt of Buyer’s written report.

ARTICLE XII

POST-CLOSING RIGHTS AND OBLIGATIONS

12.1Transfer Taxes and Recording Fees. Buyer shall pay all sales, transfer, use or similar taxes occasioned by the sale or transfer of the Properties and all documentary, transfer, filing, licensing, and recording fees required in connection with the processing, filing, licensing or recording of any assignments, titles or bills of sale (collectively, the “Transfer Taxes”).

12.2Further Assurances; Cooperation. From time to time after Closing, Seller and Buyer shall each execute, acknowledge and deliver to the other such further instruments and take such other action as may be reasonably requested in order to accomplish more effectively the purposes of the transactions contemplated by this Agreement, including assurances that Seller and Buyer are financially capable of performing any indemnification required hereunder. Subject to the terms and conditions of this Agreement, at any time or from time to time after the Closing, at any Party’s request and without further consideration, the other Party shall take such other actions as such requesting Party may reasonably request, at such requesting Party’s expense, in order to effectuate the transactions contemplated by this Agreement.

ARTICLE XIII

ASSUMPTION OF OBLIGATIONS AND INDEMNIFICATION

13.1Assumption of Liabilities and Obligations.

(a)For purposes of this Agreement, “Assumed Obligations” shall mean any and all debts, losses, liabilities, duties, claims, obligations (including but not limited to those arising out of any demand, assessment, settlement, judgment or compromise relating to any actual or threatened legal action), taxes, costs and expenses (including but not limited to any reasonable attorneys’ fees and any and all expenses whatsoever incurred in investigating, preparing or defending any legal action), matured or unmatured, absolute or contingent, accrued or unaccrued, liquidated or unliquidated, known or unknown, including any of the foregoing arising under, out of or in connection with any legal action, any order or consent decree of any Governmental Agency, any award of any arbitrator, or any applicable law, rule, or regulation (including but not limited to those arising under Environmental Laws or otherwise relating to the environment and to hazardous substances), agreement, contract, commitment, or undertaking, arising out of or attributable to the Properties, whether before, at, or after the Effective Date. Upon Closing, Buyer shall assume and pay, perform, fulfill and discharge (or cause to be paid, performed, fulfilled and discharged) all Assumed Obligations; provided, however, that Buyer shall not assume any Specified Liabilities.

(b)For purposes of this Agreement, “Environmental Laws” shall mean all laws relating to (a) the control of any potential pollutant, or protection of the air, water, or land, (b) solid, gaseous, or liquid waste generation, handling, treatment, storage, disposal, transportation or other management of Hazardous Substances, (c) exposure to hazardous, toxic, or other substances alleged to be harmful, and (d) remediation of contamination or restoration of environmental quality. “Environmental Laws” shall include, but are not limited to, the Clean Air Act, 42 U.S.C. § 7401 et seq., the Clean Water Act, 33 U.S.C. § 1251 et seq., the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et seq., the Emergency Planning and Community Right-to-Know Act, 42 U.S.C. § 11001 et seq., the Toxic Substances Control Act, 33 U.S.C. § 1251 et seq., the Safe Drinking Water Act, 42 U.S.C. § 300f et seq., and the Comprehensive Environmental Response, Compensation, and Liability Act, 42 U.S.C. § 9601 et seq.

13.2Survival; Indemnification.

(a)Survival. The representations, warranties and covenants of each of Seller and Buyer herein, and Seller’s special warranty set forth in the Assignment, shall survive for twelve (12) months following Closing; provided that, the foregoing survival periods shall not limit or affect the Parties’ respective indemnification obligations in this Section 13.2 and the Fundamental Representations shall survive for twenty-four (24) months from the Closing Date.

(b)Seller’s Indemnification of Buyer. Effective from and after the Closing, subject to the limitations set forth this Section 13 and otherwise in this Agreement, Seller and its successors and assigns shall be responsible for, shall pay, and will DEFEND, INDEMNIFY and HOLD HARMLESS Buyer and its Affiliates, and all of its and their respective equity holders, partners, members, directors, officers, managers, employees, agents and representatives (collectively, the “Buyer Indemnified Parties”) from and against any and all claims, causes of actions, payments, charges, interest assessments, judgments, liabilities, losses, damages, penalties, fines or costs and expenses, including any reasonable fees of attorneys, experts, consultants, accountants and other professional representatives and reasonable legal or other expenses incurred in connection therewith and including liabilities, costs, losses and damages for personal injury, illness or death, property damage, contracts claims, torts or otherwise (collectively, “Liabilities”) arising out of, resulting from, based on, associated with, or relating to (i) any breach by Seller of any of its representations or warranties set forth in this Agreement, the Assignment, and/or the Seller’s Certificate; (ii) any breach by Seller of any of its covenants or agreements set forth in this Agreement; or (iii) the Specified Liabilities. Notwithstanding anything herein to the contrary:

(i)Seller shall not be required to indemnify Buyer with respect to any Liabilities unless Buyer has provided Seller with a notice pursuant to Section 13.2(c) during the applicable survival period.

(ii)Seller shall not be required to indemnify Buyer for any individual claim of Liabilities of less than Fifty Thousand Dollars ($50,000.00) (“Individual Claim Threshold”).

(iii)Seller shall not be required to indemnify Buyer unless, and then only to the extent that, Liabilities that exceed the Individual Claim Threshold, exceeds one percent of the Purchase Price (1%).

(iv)Seller shall not be required to indemnify Buyer for the amount of any Liabilities in excess of thirty-five percent (35%) of the Purchase Price unless such indemnification is due to a breach of Seller’s Fundamental Representations.

(1)For purposes of this Agreement, the term “Fundamental Representations” means the representations and warranties of Seller set forth in Section 6.1, Section 6.2, Section 6.3, Section 6.5, Section 6.6, Section 6.8, Section 6.11, Section 6.13, and Section 6.21.

(c)Buyer’s Indemnification of Seller. Effective from and after the Closing, Buyer shall be responsible for, shall pay, and will DEFEND, INDEMNIFY and HOLD HARMLESS Seller and its affiliates, and all of their respective equity holders, partners, members, directors, officers, managers, employees, agents and representatives, if applicable (collectively, the “Seller Indemnified Parties”) from and against any and all Liabilities arising out of, resulting from, based on, associated with, or relating to: (i) any breach by Buyer of Buyer’s representations, warranties, covenants or agreements set forth in this Agreement or (ii) the Assumed Obligations. Notwithstanding anything contained herein to the contrary, Buyer shall not be required to indemnify Seller with respect to any Liabilities unless Seller has provided Buyer with a notice pursuant to Section 13.2(d) during the applicable survival period.

(d)Notification. As soon as reasonably practical after obtaining knowledge thereof, the Party having the right to be indemnified (the “Indemnified Party”) shall notify the Party having an obligation to indemnify such Indemnified Party (“Indemnifying Party”) of any claim or demand which the Indemnified Party has determined has given or could give rise to a claim for indemnification under this Section 13.2. Such notice shall specify the agreement, covenant, representation or warranty or other basis for indemnification under this Agreement with respect to which the claim is made, the facts giving rise to the claim and the alleged basis for the claim, and the amount (to the extent then determinable) of Liability for which indemnity is asserted. In the event any action, suit or proceeding is brought with respect to which a Party may be obligated to provide indemnity and/or defend under this Section 13.2, and the Indemnifying Party admits its liability therefor and assumes the defense of such action, suit or proceeding, the Indemnified Party shall have the right to be represented by its own counsel in any such action, suit or proceeding, and defend such action, suit or proceeding with respect to itself at the expense of the Indemnifying Party; provided that, notwithstanding the foregoing, if counsel for the Indemnified Party or Indemnifying Party determines in good faith that there is a conflict between the positions of the Indemnifying Party and the Indemnified Party in conducting the defense of such claim or that there are legal defenses available to such Indemnified Party different from or in addition to those available to the Indemnifying Party, then counsel for each of the Indemnified Party and Indemnifying Party shall be entitled, if such Party so elects, to participate in or conduct the defense to the extent reasonably determined by such counsel to protect the interests of the Indemnifying Party or Indemnified Party, as applicable, at the expense of the Indemnifying Party; provided that in no event shall the Indemnifying Party be required to pay the fees and expenses of more than one counsel selected by the Indemnified Party. Any settlement or compromise of any action, suit or proceeding by the Indemnified Party that the Indemnifying Party has admitted in writing its liability hereunder with respect to the entirety of an action, suit or proceeding shall require the consent of the Indemnifying Party (which shall not be unreasonably withheld, conditioned or delayed). Subject to the foregoing provisions of this Section 13.2, neither Party shall, without the other Party’s prior written consent, settle, compromise, confess or permit judgment by default in any action, suit or proceeding if such action would create or attach any Liability to the other Party. The Parties agree to make available to each other, and to their respective counsel and accountants, all information and documents reasonably available to them which relate to any action, suit or proceeding for which the other Party owes indemnity under this Section 13.2, and the Parties agree to render to each other such assistance as they may reasonably require of each other in order to ensure the proper and adequate defense of any such action, suit or proceeding; provided, however, that the Parties shall not be required to make available information and documents that would constitute a breach or waiver of the attorney-client privilege or violate any obligation of confidentiality binding on such disclosing Party. Subject to the terms of this Section 13.2(d), within twenty (20) days of receipt of written notice by an Indemnified Party to the Indemnifying Party, the Indemnifying Party will reimburse the Indemnified Party for all documented out-of-pocket payments, costs and expenses, including

amounts paid in settlement, incurred by the Indemnified Party in connection with any Liability which such Indemnified Party is entitled to indemnification by the Indemnified Party pursuant to this Section 13.2.

(e)Exclusive Remedy. Notwithstanding anything to the contrary contained in this Agreement and except for Buyer’s rights with respect to the express special warranty of title in the Assignment (as such rights are limited by the express terms of this Agreement), from and after Closing, Seller’s and Buyer’s sole and exclusive remedy against each other with respect to this Agreement and the transactions contemplated hereby (including, without limitation, breaches of the representations, warranties, covenants, and agreements of the Parties contained in this Agreement is set forth in this Section 13.2 and if no such right of indemnification is expressly provided therein, then such claims are hereby waived to the fullest extent permitted by applicable law.

(f)Purchase Price Adjustment. The Parties shall treat, for applicable tax purposes, any amounts paid pursuant to this Section 13 as an adjustment to the Purchase Price unless otherwise required by applicable Law.

13.3Insurance. Intentionally removed.

13.4Reservation as to Non-Parties. Nothing herein is intended to limit or otherwise waive any recourse Buyer or Seller may have against any non-Party for any obligations or liabilities that may be incurred with respect to the Properties.

ARTICLE XIV

ENVIRONMENTAL MATTERS

14.1Notice of Environmental Defects.

(a)Environmental Defects Notice. Buyer must deliver no later than 5:00 p.m. (Denver, Colorado time) on the date that is twenty (20) Business Days after the Execution Date (the “Environmental Claim Date”) claim notices to Seller meeting the requirements of this Section 14.1(a) (collectively the “Environmental Defect Notices” and individually an “Environmental Defect Notice”) setting forth any matters which, in Buyer’s good faith opinion, constitute Environmental Defects and which Buyer intends to assert as Environmental Defects pursuant to this Section 14.1. For all purposes of this Agreement, but subject to Buyer’s remedy for a breach of Seller’s representation contained in Section 6.13 and the corresponding representation in the Seller’s Certificate, Buyer shall be deemed to have waived, and Seller shall have no liability for, any Environmental Defect which Buyer fails to assert as an Environmental Defect by a properly delivered Environmental Defect Notice received by Seller on or before the Environmental Claim Date. To be effective, each Environmental Defect Notice shall be in writing and shall include (i) a description of the matter constituting the alleged Environmental Defect (including the applicable Environmental Law violated or implicated thereby) and the Properties affected by such alleged Environmental Defect, (ii) the Allocated Value of the Properties (or portions thereof) affected by such alleged Environmental Defect, (iii) supporting documents reasonably necessary for Seller to verify the existence of such alleged Environmental Defect, and (iv) Buyer’s good faith calculation of the Remediation Amount (defined in Section 14.1(a)(ii)) (itemized in reasonable detail) that Buyer asserts is attributable to such alleged Environmental Defect. Buyer’s calculation of the Remediation Amount included in the Environmental Defect Notice must describe in reasonable detail the Remediation proposed for the alleged Environmental Defect and identify all assumptions used by the Buyer in calculating the Remediation Amount, including the standards that Buyer asserts must be met to comply with Environmental Laws. To give Seller an opportunity to commence reviewing and curing Environmental Defects, Buyer agrees to give Seller, on or before the end of each calendar week prior to the Environmental Claim Date, written notice of all alleged Environmental Defects discovered by Buyer during the preceding calendar week, which notice

may be preliminary in nature and supplemented prior to the Environmental Claim Date. Buyer may not assert as an Environmental Defect any environmental condition disclosed in the schedules to this Agreement.

(i)For purposes of this Agreement, the term “Environmental Defect” shall mean (a) a condition existing on the Effective Date with respect to the air, soil, subsurface, surface waters, ground waters and sediments that causes a Property (or Seller with respect to a Property) not to be in compliance with all Environmental Laws or (b) the existence as of the Effective Date with respect to the Properties or the operation thereof of any environmental pollution, contamination or degradation where remedial or corrective action is presently required (or if known, would be presently required) under Environmental Laws; provided, however, that, any plugging and abandonment obligations shall not constitute an Environmental Defect.

(ii)For purposes of this Agreement, the term “Remediation Amount” shall mean, with respect to an Environmental Defect, the present value as of the Closing Date of the cost to remediate the Environmental Defect, net to Seller’s working interest in the applicable Property.

(b)Seller’s Right to Cure. Seller shall have the right, but not the obligation, to attempt, at its sole cost, to cure at any time prior to the Closing Date (or, if applicable, by the Final Settlement Date), any Environmental Defects of which it has been advised by Buyer. An election by Seller to attempt to cure an Environmental Defect shall be without prejudice to its rights under Section 14.1(f) and shall not constitute an admission against interest or a waiver of Seller’s right to dispute the existence, nature or value of, or cost to cure, the alleged Environmental Defect.

(c)Remedies for Environmental Defects. Subject to Seller’s continuing right to dispute the existence of an Environmental Defect or the Remediation Amount asserted with respect thereto, in the event that any Environmental Defect timely and effectively asserted by Buyer in accordance with Section 4.1(a) is not waived in writing by Buyer prior to the Closing Date, Seller shall, at its sole option, elect to:

(i)retain the entirety of the Property that is subject to such Environmental Defect, together with all associated Properties, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Properties and such associated Properties; or

(ii)cure the alleged Environmental Defect by the Final Settlement Date.

If Seller fails to elect in writing one of the remedies set forth in this Section 14.1(c) above prior to Closing with respect to any Environmental Defect, then Seller shall be deemed to have elected the remedy in Section 4.1(c)(i).

(d)Subsequent Closing. If pursuant to Section 14.1(c)(i), Seller withholds a Property from Closing due to an Environmental Defect, and such Environmental Defect is cured by the Final Settlement Date; then on or before the date for delivery of the Final Adjustment Statement, (i) Seller shall convey to Buyer all such affected Properties at a mutually agreed upon time and location in a manner consistent with Section 4.2 and Section 4.3, and (ii) contemporaneously with such subsequent closing, Buyer shall pay to Seller the Allocated Value (or applicable portion) of such Property (as adjusted pursuant to Section 2.4) by wire transfer of immediately available funds.

(e)Environmental Deductibles. Notwithstanding anything to the contrary in this Agreement, (i) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Seller for any individual Environmental Defect for which the Remediation Amount does not exceed

twenty-five thousand dollars ($25,000) (the “Individual Environmental Defect Threshold”); and (ii) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Seller for any Environmental Defect for which the Remediation Amount exceeds the Individual Environmental Defect Threshold unless (A) the amount of the sum of (1) the aggregate Remediation Amounts of all such Environmental Defects asserted against Seller that exceed the Individual Environmental Defect Threshold (but excluding any Environmental Defects cured by Seller) exceeds (B) two percent (2%) of the Purchase Price (the “Environmental Defect Deductible”), after which point Buyer shall be entitled to adjustments to the Purchase Price or other applicable remedies available hereunder, but only with respect to the amount by which the aggregate amount of such Remediation Amounts exceeds the Environmental Defect Deductible.

(f)Environmental Dispute Resolution. Seller and Buyer shall attempt to agree in writing on all Environmental Defects and Remediation Amounts prior to Closing. If Seller and Buyer are unable to agree in writing by Closing, the Environmental Defects and Remediation Amounts in dispute shall be exclusively and finally resolved by arbitration pursuant to this Section 14.1(f). There shall be a single arbitrator, who shall be an environmental attorney or consultant with at least fifteen (15) years’ experience in environmental matters involving oil and gas producing properties in the regional area in which the affected Properties are located, as selected by mutual written agreement of Buyer and Seller within fifteen (15) days after the Closing Date, and absent such agreement, by the Houston, Texas office of the AAA (the “Environmental Arbitrator”). Each of Buyer and Seller shall submit to the Environmental Arbitrator its proposed resolution of Environmental Defects and Remediation Amounts for each Environmental Defect in writing. The proposed resolution shall include the best offer of the submitting Party in a single monetary amount that such Party is willing to pay or accept (as applicable) as the Remediation Amount for each Environmental Defect. The arbitration proceeding shall be held in Houston, Texas and shall be conducted in accordance with the Commercial Arbitration Rules of the AAA, to the extent such rules do not conflict with the terms of this Section 14.1. The Environmental Arbitrator’s determination shall be made within thirty (30) days after submission of the matters in dispute and shall be final and binding upon the Parties, without right of appeal. In making its determination, the Environmental Arbitrator shall be bound by the rules set forth in this Section 14.1 and, subject to the foregoing, may consider such other matters as in the opinion of the Environmental Arbitrator are necessary or helpful to make a proper determination; provided, however, that the Environmental Arbitrator shall be limited to awarding only one or the other of the two proposed settlement amounts. The Environmental Arbitrator shall act as an expert for the limited purpose of determining the specific disputed Environmental Defects and Remediation Amounts submitted by either Party and may not award damages, interest or penalties to either Party with respect to any matter. The costs of the Environmental Arbitrator shall be borne equally between the Parties. To the extent that the award of the Environmental Arbitrator with respect to any Remediation Amount is not taken into account as an adjustment to the Purchase Price pursuant to Section 11.1 or Section 2.4(c), then, within ten (10) days after the Environmental Arbitrator delivers written notice to Buyer and Seller of his award with respect to any Remediation Amount, and subject to Section 14.1(c), the Parties shall account to each other in accordance with the terms of such award. Nothing herein shall operate to cause Closing to be delayed on account of any unresolved dispute involving Environmental Defects and/or Remediation Amounts or any arbitration conducted pursuant to this Section 14.1(f), and to the extent any adjustments are not agreed upon by the Parties in writing as of Closing, the Purchase Price shall not be adjusted therefor at Closing and subsequent adjustments to the Purchase Price, if any, will be made pursuant to Section 2.4 or this Section 14.1(f).

(g)Upon reasonable notice to Seller and subject to compliance with any applicable surface use restrictions and obtaining any required consents of third parties, including third party operators of the Properties, Seller shall afford Buyer and its representatives access to the Properties during normal business hours to conduct, at Buyer’s sole cost, expense and risk, an environmental review, including a Phase I environmental site assessment and an evaluation of the Properties’ compliance with Environmental

Laws (each, an “Environmental Assessment”). For the avoidance of doubt, Seller shall promptly request access rights from third parties for Buyer to conduct such inspections and Environmental Assessments described herein. Without limiting the foregoing, upon execution of this Agreement, Seller shall make available to Buyer and its representatives upon reasonable notice during normal business hours, (i) all non-privileged environmental, health and safety, and operating records and any other nonprivileged material information in Seller’s possession relating to the condition of the Properties, and Seller’s personnel knowledgeable with respect to the Properties to permit Buyer to perform its Environmental Assessment.

ARTICLE XV

SPECIAL WARRANTY OF DEFENSIBLE TITLE

15.1Special Warranty of Defensible Title. If Closing occurs, then effective as of the Closing Date until the expiration of the SWT Survival Period (defined below), in the Assignment, Seller shall warrant Defensible Title to its interest in the Properties unto Buyer against every Person whomsoever lawfully claims the same or any part thereof by, through or under Seller and its Affiliates, but not otherwise, subject, however, to the Permitted Encumbrances. Buyer and Seller acknowledge and agree that the special warranty of Defensible Title set forth in the Assignment shall constitute a special warranty of title by, through and under Seller under the applicable laws of the State of Oklahoma.

(a)For purposes of this Article VI, the term “SWT Survival Period” shall mean the period of time commencing as of the Closing and ending at 5:00 p.m. Denver, Colorado on the twelve (12) month anniversary of the Closing Date.

ARTICLE XVI

CONSENTS TO ASSIGN; PREFERENTIAL PURCHASE RIGHTS

16.1Consents to Assign. With respect to each Consent set forth on Schedule 6.10, Seller, prior to Closing, shall use commercially best efforts to send to the holder of each such Consent a notice in compliance with the contractual provisions applicable to such Consent seeking such holder’s consent to the transactions contemplated hereby.

(a)If Seller fails to obtain a Consent set forth on Schedule 6.10 prior to Closing and the failure to obtain such Consent would cause (i) the assignment to Buyer of the Properties (or portion thereof affected thereby) to be void or (ii) the termination of a Lease or Contract under the express terms thereof (a consent satisfying (i) or (ii) a “Hard Consent”), then (1) the Property (or portion thereof) affected by such Hard Consent shall not be conveyed at the Closing, (2) the Purchase Price shall be reduced by the Allocated Value of such Properties (or portion thereof) excluded from the Properties conveyed at Closing, and (3) Seller and Buyer shall use commercially reasonable efforts to obtain the Hard Consent applicable to the transfer of such Properties following the Closing. In the event that a Hard Consent (with respect to a Property excluded pursuant to this Section 16.1) that was not obtained prior to Closing is obtained within one hundred twenty (120) days following Closing, then, within ten (10) Business Days after such Hard Consent is obtained (A) Buyer shall purchase the Property (or portion thereof) and any associated Properties (or portion thereof) that were so excluded as a result of such previously unobtained Hard Consent and pay to Seller the amount by which the Purchase Price was reduced at Closing with respect to the Property (or portion thereof) and any associated Properties so excluded (as such amount is appropriately adjusted in accordance with the other terms of this Agreement) and (B) Seller shall assign to Buyer the Property (or portion thereof) and any associated Properties so excluded at Closing pursuant to an instrument in substantially the same form as the Assignment, in each case (subject to the other terms and conditions herein) with respect to such Property (or portion thereof) and any associated Properties so excluded at Closing.

(b)If Seller fails to obtain a Consent set forth on Schedule 6.10 prior to Closing, and such Consent is not a Hard Consent, then the Property (or portion thereof) subject to such un-obtained Consent shall nevertheless be assigned by Seller to Buyer at Closing as part of the Properties.

(c)Prior to Closing, Seller shall use its commercially reasonable efforts to obtain all Consents listed on Schedule 6.10. Subject to the foregoing, Buyer agrees to provide Seller with any information or documentation that may be reasonably requested by Seller or the third-party holder(s) of such Consents in order to facilitate the process of obtaining such Consents.

(d)If pursuant to Section 16.1(a), Seller withholds a Property from Closing due to failure to obtain a Hard Consent, and such Hard Consent expires or is obtained by the Final Settlement Date; then on or before the date for delivery of the Final Adjustment Statement, (i) Seller shall convey to Buyer all such affected Properties at a mutually agreed upon time and location (a “Subsequent Closing”) in a manner consistent with Section 5.2 and Section 5.3, and (ii) contemporaneously with such Subsequent Closing, Buyer shall pay to Seller the Allocated Value (or applicable portion) of such Property (as adjusted pursuant to Section 2.4) by wire transfer of immediately available funds.

16.2 Preferential Purchase Rights. With respect to each Preferential Purchase Right set forth on Schedule 6.17, Seller, prior to Closing, shall send to the holder of each such Preferential Purchase Right a notice in compliance with the contractual provisions applicable to such Preferential Purchase Right with respect to the transactions contemplated hereby.

(a)In the event that any holder of a Preferential Purchase Right exercises such Preferential Purchase Right prior to the Closing and the time period for exercise or waiver of such Preferential Purchase right has not yet expired, the Properties subject to such Preferential Purchase Right (as well as all other Properties as may be reasonably necessary to effect the exclusion of the affected Property due to any uniformity of interest provisions, unit agreements or other contractual or operational restrictions on the transfer of such affected Property) shall be retained by Seller, the Purchase Price shall be reduced at Closing by an amount equal to the aggregate Allocated Values of such affected Properties and, subject to Article V, the Closing shall occur as to the remainder of the Properties (or interests therein).

(b)In the event that any holder of a Preferential Purchase Right fails to exercise such Preferential Purchase Right prior to the Closing and the time period for exercise or waiver of such Preferential Purchase Right has not yet expired, the Properties subject to such Preferential Purchase Right (as well as all other Properties as may be reasonably necessary to effect the exclusion of the affected Property due to any uniformity of interest provisions, unit agreements or other contractual or operational restrictions on the transfer of such affected Property) shall be retained by the Seller and the Purchase Price shall be reduced at Closing by an amount equal to the aggregate Allocated Values of such retained Properties, and, subject to Article V, the Closing shall occur as to the remainder of the Properties (or interests therein).

(c)If, subsequent to the Closing, any Preferential Purchase Right is waived, or if the time period otherwise set forth for exercising such Preferential Purchase Right expires without exercise by the holders thereof, or such holder of such Preferential Purchase Right fails to consummate the purchase of the Properties covered by such Preferential Purchase Right in accordance with the terms of the Preferential Purchase Right, in each case by the Final Settlement Date, then Seller and Buyer shall effect a Closing (subject to the other terms and conditions herein) with respect to, and Seller shall transfer to Buyer, the Properties (or interests therein) subject to such Preferential Purchase Right and any related Properties which were excluded from the Closing as provided in this Section 16.2, and Buyer shall pay or provide to Seller an amount equal to the aggregate Allocated Values of such Properties (as adjusted pursuant to Section 2.4).

ARTICLE XVII

CASUALTY LOSSES

17.1Casualty Loss.

(a)If, after the Execution Date but prior to the Closing Date, any Property is damaged or destroyed by fire or other casualty (except to the extent Buyer has an indemnification obligation to Seller for such damage, destruction or casualty under Section 13.2(c) or is taken in condemnation or under right of eminent domain (each a “Casualty Loss”), and the aggregate amount of any such Casualty Loss or taking exceeds twenty percent (20%) of the Purchase Price, either Party may terminate this Agreement. If either Party elects to terminate this Agreement pursuant to the previous sentence, Buyer will be entitled to a refund of the Deposit (including any interest and other amount earned thereon) upon such termination. If the aggregate amount of any such Casualty Loss is Twenty Percent (20%) or less of the Purchase Price, subject to Section 9.2(e), Buyer shall nevertheless be required to close. Furthermore, subject to Section 9.2(e):

(i)If the estimated losses to the Properties as a result of all Casualty Losses that occur between the Effective Date and the Closing is less than $200,000, then at Closing (A) Buyer shall assume all risk and loss associated with such Casualty Losses as an Assumed Obligation (as defined in Section 13.1(a)) (and Seller and its Affiliates shall have no liability for such Casualty Losses), (B) the Purchase Price shall not be adjusted as a result of such Casualty Losses, and (C) Seller shall pay to Buyer all sums paid to Seller by third parties by reason of any Casualty Losses insofar as with respect to the Properties and shall assign, transfer and set over to Buyer or subrogate Buyer to all of Seller’s right, title and interest (if any) in insurance claims, unpaid awards and other rights, in each case, against third parties arising out of such Casualty Losses insofar as with respect to the Properties.

(ii)If the estimated losses to the Properties as a result of all Casualty Losses that occur between the Effective Date and the Closing equals or exceeds $200,000, then at or prior to Closing, Seller shall elect in writing to either (A) restore the Property(ies) affected by such Casualty Loss to substantially their condition as of the Effective Date as promptly as practicable following the Closing, (B) adjust the Purchase Price downward by the amount of the estimated losses to the Properties as a result of such Casualty Losses, or (C) exclude the affected Property(ies) from the transaction contemplated hereby and reduce the Purchase Price by the Allocated Value of such excluded Properties. In the event this clause 17.1(a)(ii) is applicable, Seller shall retain all sums paid by third parties by reason of such Casualty Losses and all rights in and to any insurance claims, unpaid awards and other rights, in each case, against Third Parties arising out of such Casualty Losses. Further, in the event clause 17.1(a)(ii)(A) above is applicable, Buyer agrees to reasonably cooperate with Seller, including by giving Seller reasonable access to the affected Properties to the extent necessary or convenient to facilitate Seller’s efforts to restore such affected Properties.

ARTICLE XVIII

EXPENSES AND TAXES; ASSET TAX ALLOCATION

18.1Transaction Expenses. Except as otherwise specifically provided in this Agreement, all fees, costs and expenses incurred by Buyer or Seller in negotiating this Agreement and the transaction documents or in consummating the transactions contemplated by this Agreement shall be paid by the Party incurring the same, including, legal and accounting fees, costs and expenses.

(a)Asset Tax Allocation.

(i)Seller shall be allocated and bear all Asset Taxes attributable to (1) any Tax period ending prior to the Effective Date and (2) the portion of any Straddle Period ending immediately

prior to the Effective Date. Buyer shall be allocated and bear all Asset Taxes attributable to (A) any Tax period beginning at or after the Effective Date and (B) the portion of any Straddle Period beginning at the Effective Date.

(1)For purposes of this Agreement, “Straddle Period” shall mean any Tax period beginning before and ending after the Effective Date.

(ii)For purposes of determining the allocations described in Section 18.1(a)(i) above, (1) Asset Taxes that are attributable to the severance or production of Hydrocarbons (other than such Asset Taxes described in clause (3), below) shall be allocated to the period in which the severance or production giving rise to such Asset Taxes occurred, (2) Asset Taxes that are based upon or related to sales or receipts or imposed on a transactional basis (other than such Asset Taxes described in clause (1) or (3)), shall be allocated to the period in which the transaction giving rise to such Asset Taxes occurred, and (3) Asset Taxes that are ad valorem, property or other Asset Taxes imposed on a periodic basis pertaining to a Straddle Period shall be allocated between the portion of such Straddle Period ending immediately prior to the Effective Date and the portion of such Straddle Period beginning at the Effective Date by prorating each such Asset Tax based on the number of days in the applicable Straddle Period that occur before the date on which the Effective Date occurs, on the one hand, and the number of days in such Straddle Period that occur on or after the date on which the Effective Date occurs, on the other hand. For purposes of clause (3) of the preceding sentence, the period for such Asset Taxes shall begin on the date on which ownership of the applicable Properties gives rise to Liability for the particular Asset Tax and shall end on the day before the next such date.

(iii)To the extent the actual amount of an Asset Tax is not known at the time an adjustment is to be made with respect to such Asset Tax pursuant to Section 2.4 or Section 11.1, as applicable, the Parties shall utilize the most recent information available in estimating the amount of such Asset Tax for purposes of such adjustment. To the extent the actual amount of an Asset Tax (or the amount thereof paid or economically borne by a Party) is ultimately determined to be different than the amount (if any) that was taken into account in the Final Adjustment Statement as finally determined pursuant to Section 2.4(c), timely payments will be made from one Party to the other to the extent necessary to cause each Party to bear the amount of such Asset Tax that is allocable to such Party under Section 18.1(a)(i).

(b)Certain Tax Returns and Payment Mechanics. After the Closing Date, Buyer shall (i) be responsible for paying any Asset Taxes relating to any Tax period that ends before or includes the Closing Date that become due and payable after the Closing Date and shall file with the appropriate Governmental Agency any and all Tax Returns required to be filed after the Closing Date with respect to such Asset Taxes, (ii) submit each such Tax Return to Seller for its review and comment reasonably in advance of the due date therefor, and (iii) timely file any such Tax Return, incorporating any comments received from Seller prior to the due date therefor. The Parties agree that (1) this Section 18.1(b) is intended to solely address the timing and manner in which certain Tax Returns relating to Asset Taxes are filed and the Asset Taxes shown thereon are paid to the applicable taxing authority, and (2) nothing in this Section 18.1(b) shall be interpreted as altering the manner in which Asset Taxes are allocated to and economically borne by the Parties (except for any penalties, interest or additions to Tax imposed as a result of any breach by Buyer of its obligations under this Section 18.1(b), which shall be borne by Buyer).

(c)Tax Refunds. Seller shall be entitled to any and all refunds of Asset Taxes allocated to Seller pursuant to Section 18.1(a), and Buyer shall be entitled to any and all refunds of Asset Taxes allocated to Buyer pursuant to Section 18.1(a). If a Party or its Affiliate receives a refund of Asset Taxes to which the other Party is entitled pursuant to this Section 18.1(c), such recipient Party shall forward

to the entitled Party the amount of such refund within thirty (30) days after such refund is received, net of any reasonable costs or expenses incurred by such recipient Party in procuring such refund.

(d)Cooperation. The Parties shall cooperate fully, as and to the extent reasonably requested by the other Party, in connection with the filing of Tax Returns and any audit, litigation or other proceeding with respect to Taxes relating to the Properties. Such cooperation shall include the retention and (upon the other Party’s request) the provision of records and information that are relevant to any such Tax Return or audit, litigation or other proceeding and making employees available on a mutually convenient basis to provide additional information and explanation of any material provided under this Agreement. The Parties agree to retain all books and records with respect to Tax matters pertinent to the Properties relating to any taxable period beginning before the Closing Date until the expiration of the statute of limitations of the respective taxable periods and to abide by all record retention agreements entered into with any Governmental Agency.

(e)Tax Contests. If, after the Closing Date, Buyer receives notice of an audit or administrative or judicial proceeding with respect to any Asset Tax or Tax Return with respect to Asset Taxes related to any taxable period ending prior to the Effective Date (a “Tax Contest”), Buyer shall notify Seller within ten (10) days of receipt of such notice. Seller shall have the option, at its sole cost and expense, to control any such Tax Contest and may exercise such option by providing written notice to Buyer within fifteen (15) days of receiving notice of such Tax Contest from Buyer; provided that if Seller exercises such option, Seller shall (i) keep Buyer reasonably informed of the progress of such Tax Contest, (ii) permit Buyer (or Buyer’s counsel) to participate, at Buyer’s sole cost and expense, in such Tax Contest, including in meetings with the applicable Governmental Agency, and (iii) not settle, compromise and/or concede any portion of such Tax Contest without the consent of Buyer, which consent shall not be unreasonably withheld, conditioned or delayed. If, after the Closing Date, Buyer receives notice of an audit or administrative or judicial proceeding with respect to any Asset Tax or Tax Return with respect to Asset Taxes related to a Straddle Period (a “Straddle Period Tax Contest”), Buyer shall notify Seller within ten (10) days of receipt of such notice. Buyer shall control any Straddle Period Tax Contest; provided that Buyer shall (A) keep Seller reasonably informed of the progress of such Straddle Period Tax Contest, (B) permit Seller (or Seller’s counsel) to participate, at Seller’s sole cost and expense, in such Straddle Period Tax Contest, including in meetings with the applicable Governmental Agency and (C) not settle, compromise and/or concede any portion of such Straddle Period Tax Contest for which Seller would reasonably be expected to have an indemnification obligation hereunder, or in connection with which Seller otherwise could be adversely affected, without the consent of Seller, which consent shall not be unreasonably withheld, conditioned or delayed.

ARTICLE XIX

MISCELLANEOUS

19.1Exhibits and Schedules. The exhibits and schedules to this Agreement are hereby incorporated in this Agreement by reference and constitute a part of this Agreement.

19.2Expenses. Except as otherwise specifically provided, all fees, costs and expenses incurred by Buyer or Seller in negotiating this Agreement or in consummating the transactions contemplated by this Agreement shall be paid by the Party incurring the same, including, without limitation, engineering, land, title, legal and accounting fees, costs and expenses.

19.3Notices. All notices and communications required or permitted under this Agreement shall be in writing and addressed as set forth below. Any communication or delivery hereunder shall be deemed to have been duly made and the receiving Party charged with notice: (a) if personally delivered, when received; (b) if sent by email, when received, but only if such receipt is confirmed electronically or by the

receiving Party, including an automated confirmation of receipt; (c) if mailed, five Business Days after mailing, certified mail, return receipt requested; or (d) if sent by overnight courier, one Business Day after sending. All notices shall be addressed as follows:

If to Seller:

Red Sky Resources III, LLC

475 17^th Street, Suite 790

Denver CO 80202

Telephone: (303) 507-0108

Attention: Robert Shubin; Ed Mellor

Email: rshubin@redskyresources.com; emellor@redskyresources.com

With a copy to (which shall not constitute notice to Buyer):

Hartzog Conger Cason LLP

201 Robert S. Kerr Ave., Suite 1600

Oklahoma City, Oklahoma 73102

Attention: Tom R. Russell

Tel.: (405) 235-7000

Email: trussell@hartzoglaw.com

If to Buyer:

Evolution Petroleum Corporation

155 Dairy Ashford Rd., Suite 425

Houston, Texas 77079

Telephone: (713) 935-0122

Attention: Ryan Stash

Email: rstash@evolutionpetroleum.com

With a copy to (which shall not constitute notice to Buyer):

Greathouse Holloway McFadden Trachtenberg PLLC

4200 Montrose Blvd, Ste. 300

Houston, Texas 77006

Attention: Barry E. McFadden

Tel.: (713) 688-6789

Email: barry@greatlaw.com

19.4Headings. The headings of the Articles and Sections of this Agreement are for guidance and convenience of reference only and shall not limit or otherwise affect any of the terms or provisions of this Agreement.

19.5Counterparts; Electronic Execution. This Agreement may be executed in counterparts, each of which shall be deemed an original instrument, but all such counterparts together shall constitute but one agreement. The execution and delivery of this Agreement by any Party may be evidenced by facsimile or other electronic transmission of an executed signature page to this Agreement (including scanned documents delivered by email), which shall be binding upon all Parties the same as an original hand executed signature page.

19.6Governing Law and Venue. This Agreement and the relationship of the Parties with respect to the transactions contemplated hereby shall be governed by the Laws of the State of Oklahoma without regard to conflicts of Laws principles. Any dispute, controversy, claim, or action arising out of or relating to this Agreement and any documents contemplated hereby, each as amended from time to time, including regarding the validity or effect of this Agreement or the performance, breach, interpretation, application, or termination hereof, and any of the transactions contemplated hereunder, shall be brought in the federal or state courts located in the city of Oklahoma City, Oklahoma. Each of the Parties hereto (a) irrevocably submits to the exclusive jurisdiction of each such court in any such dispute, controversy, claim, or action, (b) waives any objection it may now or hereafter have to venue or to an inconvenient forum, (c) agrees that all such disputes, controversies, claims, and actions shall be heard and determined only in such courts, and (d) agrees not to bring any dispute, controversy, claim, or action arising out of or relating to this Agreement or any documents contemplated hereby or any of the transactions contemplated hereunder in any other court. THE PARTIES HEREBY, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, WAIVE TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM BROUGHT BY ANY PARTY AGAINST ANOTHER IN ANY MATTER WHATSOEVER ARISING OUT OF OR IN RELATION TO OR IN CONNECTION WITH THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY.

19.7Entire Agreement. This Agreement constitutes the entire understanding among the Parties with respect to the subject matter hereof, superseding all negotiations, prior discussions and prior agreements and understandings relating to such subject matter.

19.8No Third-Party Beneficiaries. This Agreement is intended only to benefit the Parties hereto and their respective permitted successors and assigns.

19.9Waiver. The waiver or failure of any Party to enforce any provision of this Agreement shall not be construed or operate as a waiver of any further breach of such provision or of any other provision of this Agreement.

19.10Limitation on Damages. The Parties hereto expressly waive any and all rights to consequential, special, incidental, punitive or exemplary damages, or loss of profits resulting from any breach of this Agreement; provided, however, that this Section 19.10 shall not limit a Party’s right to recovery hereunder for any such damages to the extent such Party is required to pay such damages to a third party in connection with a matter for which such Party is otherwise entitled to indemnification hereunder.

19.11Severability. It is the intent of the Parties that the provisions contained in this Agreement shall be severable. Should any provisions, in whole or in part, be held invalid as a matter of law, such holding shall not affect the other portions of this Agreement, and such portions that are not invalid shall be given effect without the invalid portion.

19.12Successors and Assigns. This Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors and permitted assigns. Neither this Agreement nor the rights or obligations of any Party shall be assignable or transferable by such Party without the prior written consent of the other Parties; provided, however, that Buyer may assign its rights and obligations under this Agreement (including by merger, consolidation, by operation of law or otherwise), in whole or from time to time in part, to one or more of its Affiliates, or any Person acquiring all, or substantially all, of the assets of Buyer; provided that no such transfer or assignment will release Buyer of its obligations hereunder or enlarge, alter or change any obligation of Seller to Buyer. Notwithstanding anything herein to the contrary,

on or prior to the Closing Date, Buyer may assign its rights and obligations under this Agreement to one or more of its subsidiaries upon notice to Seller. In the event the non-assigning Party consents to any such assignment, such assignment shall not relieve the assigning Party of any obligations and responsibilities hereunder, including obligations and responsibilities arising following such assignment.

19.13Amendments and Waivers. This Agreement may not be modified or amended except by an instrument or instruments in writing signed by all Parties. Any Party may, only by an instrument in writing, waive compliance by another Party with any term or provision of this Agreement on the part of such other Party to be performed or complied with.

19.14Confidentiality. Upon execution of this Agreement, that certain Confidentiality Agreement dated October 18, 2023 by and between Buyer and Seller (the “Confidentiality Agreement”) shall terminate.

19.15Publicity. No public announcement will be made by any Party with respect to the subject matter of this Agreement or the transactions contemplated herein without the prior written consent of Buyer and Seller (which consent will not be unreasonably withheld, delayed or conditioned); provided that the provisions of this Section‎ 19.15 will not prohibit (a) any disclosure required by any applicable Law (in which case the disclosing Party will provide the other Party with the opportunity to review in advance any such disclosure), (b) any disclosure made in connection with the enforcement of any right or remedy relating to the transactions contemplated by this Agreement, and (c) any disclosure by Buyer to report and disclose the status of this Agreement and the transactions contemplated herein to its lenders.

(Signature page follows this page.)

IN WITNESS WHEREOF, this Agreement has been signed by each of the Parties as of the date first above written.

SELLER:

RED SKY RESOURCES III, LLC By: RIVERDALE OIL & GAS II, LLC, its Manager
By:	/s/ EDGAR I. MELLOR
Name:	Edgar I. Mellor
Title:	Manager

BUYER:

EVOLUTION PETROLEUM CORPORATION
By:	/s/ KELLY LOYD
Name:	Kelly Loyd
Title:	President & Chief Executive Officer

Signature Page to Purchase and Sale Agreement

EXHIBIT 10.12

PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement (the “Agreement”) is entered into on January 5, 2024 (the “Execution Date”), but to be effective as of 12:01 a.m. on November 1, 2023 (the “Effective Date”), by and among Red Sky Resources IV, LLC, a Colorado limited liability company (“Seller”), and Evolution Petroleum Corporation, a Nevada corporation (“Buyer”). Each of the Seller or Buyer is sometimes individually referred to herein as a “Party” and collectively as the “Parties”.

RECITALS

WHEREAS, Seller owns certain oil, gas and mineral leases and other assets located in Blaine, Canadian, Carter, Custer, Garvin, Grady, Kingfisher, McClain, Murray and Stephens Counties, Oklahoma; and

ARTICLE I

PROPERTIES DEFINED

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(i)all Imbalances (as defined in Section 3.1(i)) relating to the Properties.

1.4Specified Liabilities.

(i)death or physical injury to any employees of Seller related to or arising out of Seller’s ownership or operation of the Properties and occurring prior to the Closing Date;

(ii)claims for compensation or reimbursement of Seller’s employees for work performed with respect to the Properties prior to the Closing Date (but excluding any Property Expenses);

(iv)Imbalances relating to the Properties that are not set forth on Schedule 6.19;

(vii)all indebtedness for borrowed money of Seller;

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(ix)all Encumbrances (as defined in Section 3.1(f)) on the Properties except for Permitted Encumbrances (as defined in Section 3.1(n)); and

(x)any unpaid Royalties with respect to Seller’s ownership or operation of the Properties occurring prior to Closing.

ARTICLE II

PURCHASE PRICE AND DEPOSIT

2.1Purchase Price. The purchase price for the Properties shall be Seventeen Million Five Hundred and Ninety-Three Thousand Dollars ($17,593,000) (the “Purchase Price”), adjusted in accordance with Section 2.4 (the “Adjusted Purchase Price”) and shall be paid as follows: Buyer shall pay Seller a Deposit (as defined in Section 2.3) upon execution of this Agreement and shall pay the balance of the Adjusted Purchase Price (less the Deposit) at Closing (as defined in Section 4.1) as further provided in this Agreement.

2.3Deposit. Contemporaneously with the execution of this Agreement, Buyer has deposited with Seller an amount equal to seven and one-half percent (7.5%) of the Purchase Price, or One Million Three Hundred and Nineteen Thousand Four Hundred Seventy-Five Dollars ($1,319,475) (the “Deposit”), in immediately available funds according to the wire instructions of Seller. The Deposit is nonrefundable to Buyer unless the transactions contemplated herein fail to close due to the reasons set forth in Section 10.1(a), (b), (d), or Section 10.2(b). The Deposit shall be held in an interest-bearing account in an institution reasonably agreeable to the Parties.

2.4Accounting Adjustments.

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(viii)Any other amount provided for elsewhere in this Agreement or otherwise agreed upon in writing by Seller and Buyer.

(iii)An amount by which the aggregate amount of all Title Defect Amounts with respect to all Title Defect Properties as determined in Section 3.5 exceeds two percent (2.0%) of the

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(viii)The amount of the unassignable Properties set forth on Schedule 1.1(d) and Schedule 1.1(f);

(ix)The Allocated Value of the Properties excluded from the transactions contemplated hereby pursuant to Section 17.1(a)(ii), Section 16.1(a), Section 16.2(a) or (b), and Section 14.1(c); and

(x)Any other amount provided for elsewhere in this Agreement or otherwise agreed upon in writing by Seller and Buyer.

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accordance herewith. Following such additional adjustments, no further adjustments shall be made under this Section 2.4.

ARTICLE III

DOCUMENT REVIEW

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(d)The term “Business Day” shall mean any day that is not a Saturday, Sunday or legal holiday in the State of Oklahoma or a federal holiday in the United States of America.

(f)The term “Encumbrance” shall mean any lien, mortgage, security interest, pledge, charge, or similar encumbrance.

(j)The term “Income Taxes” shall mean all Taxes based upon, measured by, or calculated with respect to gross or net income, and franchise taxes based upon income, capital, assets or operations.

(k)The term “Law” shall mean any applicable statute, law, rule, regulation, ordinance, order, code, ruling, writ, injunction, decree or other official act of or by any Governmental Agency.

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(r)The term “Subject Depth” shall mean with respect to any Well, the formation or formations currently being produced by such Well.

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(vi)Notwithstanding (i) – (v), if Buyer and Seller agree on the Title Defect Amount, such amount shall be the Title Defect Amount; and

(vii)The Title Defect Amount with respect to a Property shall be determined without duplication of any costs or losses included in another Title Defect Amount hereunder.

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(iv)if a Property has no Allocated Value, then such Property shall have no Seller Title Credit.

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ARTICLE IV

CLOSING

4.2Seller’s Closing Obligations. At Closing, Seller shall execute and deliver, or cause to be executed and delivered, to Buyer the following:

(a)an Assignment and Bill of Sale (the “Assignment”), from Seller, effective as of the Effective Date and substantially in the form of Exhibit B attached hereto;

(b)the Preliminary Settlement Statement;

(c)a certificate, dated as of the Closing Date, executed by a duly authorized officer of Seller, to the effect that the representations and warranties of Seller contained in Article VI shall be true

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and correct in all respects on and as of the Closing Date as though made on and as of the Closing Date (“Seller’s Certificate”);

(d)releases, in form reasonably satisfactory to Buyer, of the liens and security interests described in Schedule 4.2(d);

(e)the Records and any letters in lieu of division and transfer orders relating to the Properties in form reasonably necessary to reflect the conveyances contemplated hereby; and.

4.3Buyer’s Closing Obligations. At Closing, Buyer shall execute (as applicable) and deliver, or cause to be executed and delivered, to Seller the following:

(a)the Assignment, effective as of the Effective Date;

(b)the Preliminary Settlement Statement;

ARTICLE V

CONDITION AND FITNESS OF THE PROPERTIES

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ARTICLE VI

SELLER’S REPRESENTATIONS AND WARRANTIES

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in each jurisdiction in which the ownership of the Properties makes such licensing or qualification necessary.

6.5No Bankruptcy. There are no bankruptcy, reorganization, liquidation, or receivership proceedings pending, being contemplated by or, threatened against Seller.

6.8Title to Properties. Neither Seller nor its Affiliates has sold, transferred, or assigned any of the Properties or provided any Person rights to ownership of the Seller’s Properties.

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6.13Environmental Laws. Except as set forth on Schedule 6.13:

(a)To Seller’s knowledge, the Properties are in compliance with applicable Environmental Laws.

(c)To Seller’s knowledge, none of the Properties are subject to any unfulfilled orders, consent decrees or judgments of any Governmental Agency; and

6.16Material Contracts. Schedule 6.16 sets forth, as of the Execution Date, all Contracts of the type described below (collectively, the “Material Contracts”):

(ii)any Hydrocarbon purchase and sale, transportation, gathering, treating, processing or similar Applicable Contract that is not terminable without penalty upon ninety (90) days’ or less notice;

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(vi)any Contract between Seller and any Affiliate of Seller that is binding on the Properties and will not be terminated prior to or as of the Closing;

(vii)any Contract that provides for an area of mutual interest; and

(viii)any Contract that contains a non-compete agreement or otherwise purports to restrict, limit or prohibit the manner in which, or the locations in which, Seller may conduct its business.

6.18Royalties. To Seller’s knowledge, all Royalties and/or other Burdens with respect to Seller’s ownership of the Properties have been paid on Seller’s behalf.

6.19Imbalances. Except as set forth on Schedule 6.19, there are no Imbalances associated with the Properties as of the Effective Date. There are no agreements or obligations relating to Imbalances.

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ARTICLE VII

BUYER’S REPRESENTATIONS AND WARRANTIES

Buyer makes the following representations and warranties to Seller as of the Execution Date:

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7.5No Bankruptcy. There are no bankruptcy proceedings pending, being contemplated by or, threatened against Buyer.

7.7Funds. Buyer has sufficient funds available to enable Buyer to consummate the transactions contemplated hereby and to pay all related fees and expenses of Buyer.

ARTICLE VIII

ADDITIONAL COVENANTS

(b)Seller shall not grant a lien on or a security interest in any Properties (other than a Permitted Encumbrance); and

(i)own and maintain the Properties in an ordinary manner consistent with past practice;

(ii)not propose any operation reasonably expected to cost Seller in excess of $20,000 (net to Seller’s interest in the Properties);

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(vi)provide Buyer with copies of any and all material correspondence received from any Governmental Agency with respect to the Properties within five (5) days of the receipt thereof;

(vii)not voluntarily abandon any of the Properties other than as required pursuant to the terms of a Lease or applicable Law;

(viii)maintain its existing insurance policies relating to the Properties in such amounts and with such deductibles as are currently maintained by Seller;

(x)not commit to do any of the foregoing in clauses (ii), (iv), (v), (vii) or (ix);

(xi)obtain all Preferential Purchase Rights and other Consents required by third parties, Governmental Agency and others as may be required to consummate the transaction;

(xii)except with respect to any Excluded Assets, maintain in effect all Permits as may be necessary for Seller or its Affiliates to own and operate the Properties; and

(xiii)give prompt written notice to Buyer of any damage to or destruction of any of the Properties.

ARTICLE IX

CONDITIONS PRECEDENT TO CLOSING

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9.2Buyer’s Conditions. The obligations of Buyer at Closing are subject to, at the option the Buyer, the satisfaction or waiver at or prior to the Closing Date of the following conditions precedent:

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ARTICLE X

TERMINATION

10.1Termination. This Agreement may be terminated in accordance with the following provisions:

(a)By mutual consent of Buyer and Seller;

(b)By either Party in accordance with Section 17;

(c)By Seller if the conditions set forth in Section 9.1 are not satisfied on or before March 11, 2024, through no fault of Seller, or waived by Seller in writing, as of Closing; or

(d)By Buyer if the conditions set forth in Section 9.2 are not satisfied on or before March 11, 2024, through no fault of Buyer, or waived by Buyer in writing, as of Closing.

10.2Effect of Termination.

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(d)Intentionally Omitted.

ARTICLE XI

SETTLEMENT STATEMENT

ARTICLE XII

POST-CLOSING RIGHTS AND OBLIGATIONS

ARTICLE XIII

ASSUMPTION OF OBLIGATIONS AND INDEMNIFICATION

13.1Assumption of Liabilities and Obligations.

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13.2Survival; Indemnification.

(i)Seller shall not be required to indemnify Buyer with respect to any Liabilities unless Buyer has provided Seller with a notice pursuant to Section 13.2(c) during the applicable survival period.

(ii)Seller shall not be required to indemnify Buyer for any individual claim of Liabilities of less than Fifty Thousand Dollars ($50,000.00) (“Individual Claim Threshold”).

(iii)Seller shall not be required to indemnify Buyer unless, and then only to the extent that, Liabilities that exceed the Individual Claim Threshold, exceeds one percent of the Purchase Price (1%).

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13.3Insurance. Intentionally removed.

ARTICLE XIV

ENVIRONMENTAL MATTERS

14.1Notice of Environmental Defects.

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(ii)cure the alleged Environmental Defect by the Final Settlement Date.

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ARTICLE XV

SPECIAL WARRANTY OF DEFENSIBLE TITLE

ARTICLE XVI

CONSENTS TO ASSIGN; PREFERENTIAL PURCHASE RIGHTS

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ARTICLE XVII

CASUALTY LOSSES

17.1Casualty Loss.

ARTICLE XVIII

EXPENSES AND TAXES; ASSET TAX ALLOCATION

(a)Asset Tax Allocation.

(i)Seller shall be allocated and bear all Asset Taxes attributable to (1) any Tax period ending prior to the Effective Date and (2) the portion of any Straddle Period ending immediately

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(1)For purposes of this Agreement, “Straddle Period” shall mean any Tax period beginning before and ending after the Effective Date.

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ARTICLE XIX

MISCELLANEOUS

19.1Exhibits and Schedules. The exhibits and schedules to this Agreement are hereby incorporated in this Agreement by reference and constitute a part of this Agreement.

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If to Seller:

Red Sky Resources IV, LLC

475 17^th Street, Suite 790

Denver CO 80202

Telephone: (303) 507-0108

Attention: Robert Shubin; Ed Mellor

Email: rshubin@redskyresources.com; emellor@redskyresources.com

With a copy to (which shall not constitute notice to Buyer):

Hartzog Conger Cason LLP

201 Robert S. Kerr Ave., Suite 1600

Oklahoma City, Oklahoma 73102

Attention: Tom R. Russell

Tel.: (405) 235-7000

Email: trussell@hartzoglaw.com

If to Buyer:

Evolution Petroleum Corporation

155 Dairy Ashford Rd., Suite 425

Houston, Texas 77079

Telephone: (713) 935-0122

Attention: Ryan Stash

Email: rstash@evolutionpetroleum.com

With a copy to (which shall not constitute notice to Buyer):

Greathouse Holloway McFadden Trachtenberg PLLC

4200 Montrose Blvd, Ste. 300

Houston, Texas 77006

Attention: Barry E. McFadden

Tel.: (713) 688-6789

Email: barry@greatlaw.com

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19.8No Third-Party Beneficiaries. This Agreement is intended only to benefit the Parties hereto and their respective permitted successors and assigns.

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(Signature page follows this page.)

IN WITNESS WHEREOF, this Agreement has been signed by each of the Parties as of the date first above written.

SELLER:

RED SKY RESOURCES IV, LLC By: RIVERDALE OIL & GAS III, LLC, its Manager
By:	/s/ EDGAR I. MELLOR
Name:	Edgar I. Mellor
Title:	Manager

BUYER:

EVOLUTION PETROLEUM CORPORATION
By:	/s/ KELLY LOYD
Name:	Kelly Loyd
Title:	President & Chief Executive Officer

Signature Page to Purchase and Sale Agreement

EXHIBIT 10.13

PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement (the “Agreement”) is entered into on January 5, 2024 (the “Execution Date”), but to be effective as of 12:01 a.m. on November 1, 2023 (the “Effective Date”), by and among Coriolis Energy Partners I, LLC, a Delaware limited liability company (“Seller”), and Evolution Petroleum Corporation, a Nevada corporation (“Buyer”). Each of the Seller or Buyer is sometimes individually referred to herein as a “Party” and collectively as the “Parties”.

RECITALS

WHEREAS, Seller owns certain oil, gas and mineral leases and other assets located in Canadian, Garvin, Grady, Kingfisher, McClain and Stephens Counties, Oklahoma; and

ARTICLE I

PROPERTIES DEFINED

(d)to the extent transferable, originals (or copies if Seller does not possess originals) of all the files and records directly pertaining to the Leases and Wells (the “Records”), which Records shall include, without limitation, all contracts and contractual rights, area of mutual interest agreements; joint

venture agreements; confidentiality agreements, land and title records (including abstracts of title and title opinions), environmental, production, engineering and accounting records, easements, rights of way, obligations, and interests, including all farmout and farmin agreements, operating agreements, operations records, bottom hole agreements, crude oil, condensate and natural gas purchase and sale, gathering, transportation and marketing agreements; Hydrocarbon storage agreements; acreage contribution agreements production sales and purchase contracts, unitization and pooling agreements, communitization agreements, saltwater disposal agreements, surface leases, surface use agreements, division and transfer orders, geological files and geophysical data, daily drilling reports, well records including well data and logs; balancing agreements, pooling declarations or agreements, unitization agreements, processing agreements, facilities or equipment leases, exploration agreements, participation agreements, exchange agreements and other similar contracts and agreements, and any and all amendments, ratifications or extensions of the foregoing, including (i) any claims for take or pay or other similar payments arising before or after the Effective Date to the extent related to production of Hydrocarbons on or after the Effective Date, (ii) all rights of Seller and its Affiliates that are currently serving as operator under any joint operating agreement to serve as operator under such joint operating agreement, and (iii) to the extend not covered in (i) – (ii), any and all contracts, agreements and instruments by which the Properties are bound, or that relate to or are otherwise applicable to the Properties, insofar as such contracts are valid and existing and applicable to the Properties, or the oil, gas, and other Hydrocarbons produced from the Properties or attributable to the Properties in storage owned by Seller above custody transfer point at the Effective Date or produced on and after the Effective Date, and all proceeds attributable thereto, and other contracts or agreements covering or affecting any or all of the other Properties described herein (collectively, the “Contracts”), but exclusive of any Contracts set forth on Schedule 1.1(d) or relating to the Excluded Assets;

(i)all Imbalances (as defined in Section 3.1(i)) relating to the Properties.

1.4Specified Liabilities.

(i)death or physical injury to any employees of Seller related to or arising out of Seller’s ownership or operation of the Properties and occurring prior to the Closing Date;

(ii)claims for compensation or reimbursement of Seller’s employees for work performed with respect to the Properties prior to the Closing Date (but excluding any Property Expenses);

(iv)Imbalances relating to the Properties that are not set forth on Schedule 6.19;

(vii)all indebtedness for borrowed money of Seller;

(ix)all Encumbrances (as defined in Section 3.1(f)) on the Properties except for Permitted Encumbrances (as defined in Section 3.1(n)); and

(x)any unpaid Royalties with respect to Seller’s ownership or operation of the Properties occurring prior to Closing.

ARTICLE II

PURCHASE PRICE AND DEPOSIT

2.1Purchase Price. The purchase price for the Properties shall be Seven Million Three Hundred and Ninety-Five Thousand Dollars ($7,395,000) (the “Purchase Price”), adjusted in accordance with Section 2.4 (the “Adjusted Purchase Price”) and shall be paid as follows: Buyer shall pay Seller a Deposit (as defined in Section 2.3) upon execution of this Agreement and shall pay the balance of the Adjusted Purchase Price (less the Deposit) at Closing (as defined in Section 4.1) as further provided in this Agreement.

2.3Deposit. Contemporaneously with the execution of this Agreement, Buyer has deposited with Seller an amount equal to seven and one-half percent (7.5%) of the Purchase Price, or Five Hundred Fifty-Four Thousand Six Hundred and Twenty-Five Thousand Dollars ($554,625) (the “Deposit”), in immediately available funds according to the wire instructions of Seller. The Deposit is nonrefundable to Buyer unless the transactions contemplated herein fail to close due to the reasons set forth in Section 10.1(a), (b), (d), or Section 10.2(b). The Deposit shall be held in an interest-bearing account in an institution reasonably agreeable to the Parties.