Evolution Petroleum 10Q 2023 Q3 Quarterly report

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, 2023


☐	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 5, 2023, 33,268,686 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, 2023 and June 30, 2022	4
	Condensed Consolidated Statements of Operations (Unaudited) for the three and nine months ended March 31, 2023 and 2022	5
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the nine months ended March 31, 2023 and 2022	6
	Condensed Consolidated Statements of Changes in Stockholders’ Equity (Unaudited) for the three and nine months ended March 31, 2023 and 2022	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	37
Item 4.	Controls and Procedures	38
PART II. OTHER INFORMATION		38
Item 1.	Legal Proceedings	38
Item 1A.	Risk Factors	39
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 3.	Defaults Upon Senior Securities	39
Item 4.	Mine Safety Disclosures	39
Item 5.	Other Information	39
Item 6.	Exhibits	40
	Signatures	41

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 pay dividends and repurchase shares pursuant to our share repurchase program;

●

oil, natural gas and NGLs production and commodity mix, GHG emissions and ESG performance;

●

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;

●

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 legislation, including the costs thereof; 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 NGL;

●

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

●

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 and natural gas, 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, 2022, 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, 2023		June 30, 2022
Assets
Current assets
Cash and cash equivalents	$	18,387	$	8,280
Receivables from crude oil, natural gas, and natural gas liquids revenues		9,853		24,043
Derivative contract assets		—		170
Prepaid expenses and other current assets		2,765		3,875
Total current assets		31,005		36,368
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		105,315		110,508
Other assets		1,353		1,171
Total assets	$	137,673	$	148,047
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable	$	8,735	$	15,133
Accrued liabilities and other		9,429		11,893
Derivative contract liabilities		—		2,164
State and federal taxes payable		2,158		1,095
Total current liabilities		20,322		30,285
Long term liabilities
Senior secured credit facility		—		21,250
Deferred income taxes		6,999		7,099
Asset retirement obligations		14,592		13,899
Operating lease liability		137		—
Total liabilities		42,050		72,533
Commitments and contingencies (Note 10)
Stockholders' equity
Common stock; par value $0.001; 100,000,000 shares authorized: issued and
outstanding 33,270,909 and 33,470,710 shares as of March 31, 2023
and June 30, 2022, respectively		33		33
Additional paid-in capital		39,801		42,629
Retained earnings		55,789		32,852
Total stockholders' equity		95,623		75,514
Total liabilities and stockholders' equity	$	137,673	$	148,047

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,
	2023		2022		2023		2022
Revenues
Crude oil	$	11,799	$	14,868	$	40,062	$	34,309
Natural gas		21,598		6,070		58,816		20,698
Natural gas liquids		3,470		4,750		11,462		11,899
Total revenues		36,867		25,688		110,340		66,906
Operating costs
Lease operating costs		13,570		12,084		47,727		31,380
Depletion, depreciation, and accretion		3,383		1,737		10,439		4,489
General and administrative expenses		2,267		1,515		7,320		5,278
Total operating costs		19,220		15,336		65,486		41,147
Income (loss) from operations		17,647		10,352		44,854		25,759
Other income (expense)
Net gain (loss) on derivative contracts		270		(2,591)		513		(2,591)
Interest and other income		13		2		26		12
Interest expense		(32)		(170)		(404)		(272)
Income (loss) before income taxes		17,898		7,593		44,989		22,908
Income tax (expense) benefit		(3,941)		(1,888)		(9,938)		(5,152)
Net income (loss)	$	13,957	$	5,705	$	35,051	$	17,756
Net income (loss) per common share:
Basic	$	0.42	$	0.17	$	1.04	$	0.53
Diluted	$	0.41	$	0.17	$	1.04	$	0.52
Weighted average number of common shares outstanding:
Basic		33,013		33,009		33,108		32,933
Diluted		33,156		33,388		33,291		33,258

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,
	2023		2022
Cash flows from operating activities:
Net income (loss)	$	35,051	$	17,756
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and accretion		10,439		4,489
Stock-based compensation		1,155		868
Settlement of asset retirement obligations		(119)		—
Deferred income taxes		(100)		400
Unrealized (gain) loss on derivative contracts		(1,994)		2,398
Accrued settlements on derivative contracts		(1,130)		193
Other		(3)		(7)
Changes in operating assets and liabilities:
Receivables from crude oil, natural gas, and natural gas liquids revenues		16,483		(4,999)
Prepaid expenses and other current assets		(980)		(79)
Accounts payable and accrued liabilities		(8,146)		7,529
State and federal income taxes payable		1,063		143
Net cash provided by operating activities		51,719		28,691
Cash flows from investing activities:
Acquisition of oil and natural gas properties		(31)		(25,844)
Capital expenditures for oil and natural gas properties		(4,234)		(826)
Acquisition deposit		—		(1,470)
Net cash used in investing activities		(4,265)		(28,140)
Cash flows from financing activities:
Common stock dividends paid		(12,114)		(8,421)
Common stock repurchases, including stock surrendered for tax withholding		(3,983)		(38)
Borrowings under senior secured credit facility		—		17,000
Repayments of senior secured credit facility		(21,250)		(1,000)
Net cash (used in) provided by financing activities		(37,347)		7,541
Net increase (decrease) in cash and cash equivalents		10,107		8,092
Cash and cash equivalents, beginning of period		8,280		5,277
Cash and cash equivalents, end of period	$	18,387	$	13,369

Supplemental disclosures of cash flow information:
Non-cash investing and financing transactions:
Increase (decrease) in accrued capital expenditures for oil and natural gas properties	$	(141)	$	—
Oil and natural gas property costs attributable to the recognition of asset retirement obligations		—		2,440

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, 2023
Balances at December 31, 2022	33,808	$	34		$	43,243	$	45,861	$	—	$	89,138
Issuance of restricted common stock	101		—			—		—		—		—
Forfeitures of restricted stock	—		—			—		—		—		—
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

For the Three Months Ended March 31, 2022
Balances at December 31, 2021	33,689	$	34		$	43,067	$	19,026	$	—	$	62,127
Issuance of restricted common stock	60		—			—		—		—		—
Forfeitures of restricted stock	(22)		—			—		—		—		—
Common stock repurchases, including stock surrendered for tax withholding	—		—			—		—		(36)		(36)
Retirements of treasury stock	(7)		—			(36)		—		36		—
Stock-based compensation	—		—			340		—		—		340
Net income (loss)	—		—	��		—		5,705		—		5,705
Common stock dividends paid	—		—			—		(3,376)		—		(3,376)
Balances at March 31, 2022	33,720	$	34		$	43,371	$	21,355	$	—	$	64,760

For the Nine Months Ended March 31, 2022
Balances at June 30, 2021	33,515	$	34		$	42,541	$	12,020	$	—	$	54,595
Issuance of restricted common stock	314		—			—		—		—		—
Forfeitures of restricted stock	(102)		—			—		—		—		—
Common stock repurchases, including stock surrendered for tax withholding	—		—			—		—		(38)		(38)
Retirements of treasury stock	(7)		—			(38)		—		38		—
Stock-based compensation	—		—			868		—		—		868
Net income (loss)	—		—			—		17,756		—		17,756
Common stock dividends paid	—		—			—		(8,421)		—		(8,421)
Balances at March 31, 2022	33,720	$	34		$	43,371	$	21,355	$	—	$	64,760

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 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, production enhancement, and other exploitation efforts on its oil and natural gas properties.

The Company’s producing properties consist of non-operated interests in the following areas: the Jonah Field in Sublette County, Wyoming, a natural gas and natural gas liquids producing field; the Williston Basin in North Dakota, producing oil and natural gas properties; the Barnett Shale located in North Texas, natural gas and natural gas liquids producing properties; the Hamilton Dome Field located in Hot Springs County, Wyoming, a secondary oil 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 (“EOR”) 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 2022 Annual Report on Form 10-K for the fiscal year ended June 30, 2022, as filed with the SEC on September 14, 2022. 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 (the “Company”). All significant intercompany transactions have been eliminated in consolidation. The unaudited condensed consolidated financial statements for the previous year may include certain reclassifications to conform to the current presentation. To conform with the current year presentation, “Other receivables” disclosed in Footnote 13, “Additional Financial Statement Information” is included with “Prepaids expenses and other current assets” instead of “Receivables from crude oil, natural gas, and natural gas liquids revenues” at June 30, 2022 on the unaudited condensed consolidated balance sheets. This reclassification has no impact on previously reported 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.

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

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

gas, and natural gas liquids (“NGL”) revenues and expenses. The Company analyzes estimates and judgements 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 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 is currently evaluating the impact of ASU 2016-13 but does not expect that it will 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 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 disaggregates the Company’s revenues by major product for the three and nine months ended March 31, 2023 and 2022 (in thousands):


	Three Months Ended				Nine Months Ended
	March 31,				March 31,
	2023		2022		2023		2022
Revenues
Crude oil	$	11,799	$	14,868	$	40,062	$	34,309
Natural gas		21,598		6,070		58,816		20,698
Natural gas liquids		3,470		4,750		11,462		11,899
Total revenues	$	36,867	$	25,688	$	110,340	$	66,906

��

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. (“Enterprise”) 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 receives payment from the sale of oil and natural gas production one to two months after delivery.

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

Note 3. Acquisitions

On April 1, 2022, the Company closed the acquisition of non-operated interests in the Jonah Field in Sublette County, Wyoming from Exaro Energy III, LLC (the “Jonah Field Acquisition”). After taking into account customary closing adjustments and an effective date of February 1, 2022, total cash consideration for the Jonah Field Acquisition was $26.4 million. The Company accounted for this transaction as an asset acquisition and allocated all of the purchase price (including $0.2 million of transaction costs) to proved oil and natural gas properties. Approximately, $1.6 million of the consideration transferred related to deposits transferred to the Company at closing, the largest related to a $1.2 million deposit with Enterprise for a gas gathering contract which was recorded to “Other assets” on the unaudited condensed consolidated balance sheets. In addition, the Company recognized $3.0 million in non-cash asset retirement obligations. The transaction was funded with cash on hand and $17.0 million in borrowings under the Company’s Senior Secured Credit Facility.

On January 14, 2022, the Company completed the acquisition of non-operated working interests in the Williston Basin in North Dakota from Foundation Energy Fund VII-A, LP and Foundation Energy Management, LLC (the “Williston Basin Acquisition”). After taking into account customary closing adjustments and an effective date of June 1, 2021, cash consideration was $25.2 million which included $0.3 million of capitalized transaction costs related to the acquisition. The Company accounted for the transaction as an asset acquisition and allocated all of the purchase price (including capitalized transaction costs) to proved oil and natural gas properties. The Company also recognized $2.4 million in non-cash asset retirement obligations. The transaction was funded with cash on hand and $16.0 million in borrowings under the Company’s Senior Secured Credit Facility.

On May 7, 2021, the Company completed the acquisition of non-operated oil and natural gas properties in the Barnett Shale from Tokyo Gas Americas for net cash consideration of $17.4 million, after taking into account customary closing

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adjustments, and also recognized $2.8 million in non-cash asset retirement obligations (the “Barnett Shale Acquisition”). The Company accounted for the transaction as an asset acquisition and allocated all of the purchase price (including capitalized transaction costs) to proved oil and natural gas properties. During the nine months ended March 31, 2022, the Company recorded a downward purchase price adjustment of $0.9 million related to its acquisition of the Barnett Shale as a result of the completion of the final settlement statement.

In accordance with the FASB’s authoritative guidance on asset acquisitions, the Company allocated the cost of the above acquisitions to the assets acquired and liabilities assumed based on a relative fair value basis of the assets acquired and liabilities assumed, with no recognition of goodwill or bargain purchase gain recorded. Incremental legal and professional fees related directly to the acquisitions were capitalized as part of the acquisition cost. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize market assumptions of market participants.

Note 4. Property and Equipment

Property and equipment as of March 31, 2023 and June 30, 2022 consisted of the following (in thousands):


	March 31, 2023		June 30, 2022
Oil and natural gas properties
Property costs subject to amortization	$	193,039	$	188,634
Less: Accumulated depletion, depreciation, and impairment		(87,724)		(78,126)
Oil and natural gas properties, net	$	105,315	$	110,508

As of March 31, 2023 and June 30, 2022, all oil and natural gas property costs were subject to amortization. Depletion of oil and natural gas properties was $9.6 million and $4.1 million for the nine months ended March 31, 2023 and 2022, respectively.

During the nine months ended March 31, 2023 and 2022, the Company incurred development capital expenditures of $4.4 million and $0.8 million, respectively.

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 and properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated 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.

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 West Texas Intermediate (“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 differentials to WTI 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 necessary.

At March 31, 2022, 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, 2022 of the WTI crude oil spot price of $75.28 per barrel and Henry Hub natural gas spot price of $4.15 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $40.07, which was based on historical prices received as NGLs do not have any single comparable reference index price. Using these prices, at March 31, 2022 the cost center ceiling was higher than the capitalized costs of oil and natural gas properties, and as a result, no write-down was necessary.

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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 replaces 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%.

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, 2023, the Company did not have any borrowings outstanding under its Senior Secured Credit Facility, resulting in $50.0 million of available borrowing capacity. For the nine months ended March 31, 2023 and 2022, the weighted average interest on borrowings under the Senior Secured Credit Facility was 5.25% and 3.04%, respectively. As of March 31, 2023, the Company was in compliance with the financial covenants under the Senior Secured Credit Facility.

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 Ninth Amendment, as discussed above.

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On August 5, 2021 the Company entered into the Seventh Amendment to the Senior Secured Credit Facility which, among other things, added definitions for the terms “Acquired Entity or Mineral Interests” and “Acquired Entity or Mineral Interests EBITDA Adjustment.” Additionally, the consolidated tangible net worth covenant level was reduced to $40.0 million from $50.0 million.

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 returns are open to audit under the statute of limitations for the fiscal years ended June 30, 2019 through June 30, 2021 for federal tax purposes and for the fiscal years ended June 30, 2018 through June 30, 2021 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 the nine months ended March 31, 2023 the Company recognized income tax expense of $9.9 million and had an effective tax rate of 22.1% compared to an income tax expense of $5.2 million and an effective tax rate of 22.5% for the nine months ended March 31, 2022. During the nine months ended March 31, 2023 and 2022, the Company recognized an income tax benefit of $0.1 million for both periods related to the vesting of restricted stock awards.

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, North Dakota, and Texas, due to 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 policy 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 policies 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, 2023, all of the Company’s derivative contracts had expired. The Company has no open derivative contracts as of March 31, 2023, and the Company did not post collateral under any of its derivative contracts during the year as they were secured under the Company’s Senior Secured Credit Facility.

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The Company has in the past, and may utilize in the future, costless put/call collars and 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 June 30, 2022 (the “mark-to-market valuation”). 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, 2023 and June 30, 2022 (in thousands):


Derivatives not designated
as hedging contracts	Balance sheet	Derivative Contract Assets				Balance sheet	Derivative Contract Liabilities
under ASC 815	location	March 31, 2023		June 30, 2022		location	March 31, 2023		June 30, 2022
Commodity contracts	Current assets - derivative contract assets	$	—	$	170	Current liabilities - derivative contract liabilities	$	—	$	2,164
Commodity contracts	Other assets - derivative contract assets		—		—	Long term liabilities - derivative contract liabilities		—		—
Total derivatives not designated as hedging contracts under ASC 815		$	—	$	170		$	—	$	2,164

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, 2023 and 2022 (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	2023		2022		2023		2022
Commodity contracts:
Realized gain (loss) on derivative contracts	Other income and expenses - net gain (loss) on derivative contracts	$	465	$	(193)	$	(1,481)	$	(193)
Unrealized gain (loss) on derivative contracts	Other income and expenses - net gain (loss) on derivative contracts		(195)		(2,398)		1,994		(2,398)
Total net gain (loss) on derivative contracts		$	270	$	(2,591)	$	513	$	(2,591)

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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 June 30, 2022 (in thousands):


	Derivative Contracts Assets		Derivative Contracts Liabilities
Offsetting of Derivative Assets and Liabilities	June 30, 2022		June 30, 2022
Gross amounts presented in the Consolidated Balance Sheet	$	170	$	2,164
Amounts not offset in the Consolidated Balance Sheet		(170)		(170)
Net amount	$	—	$	1,994

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


	June 30, 2022
	Level 1		Level 2		Level 3		Total
Assets
Derivative contract assets	$	—	$	170	$	—	$	170

Liabilities
Derivative contract liabilities	$	—	$	2,164	$	—	$	2,164

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Derivative contracts listed above as Level 2 include 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.

Historically, the Company’s derivative contracts were 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. To date, the Company has not experienced such nonperformance.

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.

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, 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) (in thousands):


	March 31, 2023
Asset retirement obligations — beginning of period	$	13,921
Liabilities settled		(119)
Accretion of discount		841
Asset retirement obligations — end of period		14,643
Less: current asset retirement obligations		(51)
Long-term portion of asset retirement obligations	$	14,592

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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 estimatable. 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, 2023, the Company had 33,270,909 shares of common stock outstanding.

The Company began paying quarterly cash dividends on common stock in December 2013. As of March 31, 2023, the Company has cumulatively paid over $98.4 million in cash dividends. The Company paid dividends of $12.1 million and $8.4 million to its common stockholders during the nine months ended March 31, 2023 and 2022, respectively. The following table reflects the dividends paid per share within the respective three-month periods:


	Fiscal Year
	2023		2022
Third quarter ended March 31,	$	0.120	$	0.100
Second quarter ended December 31,		0.120		0.075
First quarter ended September 30,		0.120		0.075

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 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.

Once the Company completed repayment of borrowings on its Senior Secured Credit Facility and emerged from its blackout period in December 2022, 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 included a 30-day cooling off period that did not allow repurchases to commence until January 2023. The plan is effective until June 30, 2023, unless extended, renewed or terminated by the Company, and has a maximum authorized amount of $5.0 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, 2023, 0.6 million shares of the Company’s common stock were repurchased under the plan at a total cost of

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approximately $3.9 million, including incremental direct transaction costs. These treasury shares were subsequently cancelled.

During the nine months ended March 31, 2023 and 2022, the Company also acquired treasury stock upon the vesting 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.

The following table summarizes all treasury stock purchases during the nine months ended March 31, 2023 and 2022:


	Nine Months Ended
	March 31,
	2023		2022
Number of treasury shares acquired⁽¹⁾		650,435		7,385
Average cost per share⁽¹⁾	$	6.12	$	5.09
Total cost of treasury shares acquired	$	3,982,849	$	37,596

(1)	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, 2022, 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, 2023, 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, 2023 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, 2023 and June 30, 2022, approximately 1.3 million shares and 1.8 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. For the three and nine months ended March 31, 2023, the Company recognized $0.5 million and $1.2 million, respectively, of stock-based compensation expense. During the three and nine months ended March 31, 2022, the Company recognized $0.3 million and $0.9 million, respectively, of 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

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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.

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, 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 approximately 0.05 million performance-based contingent stock units.

During the nine months ended March 31, 2022, 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 of performance-based contingent stock units.

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For performance-based awards granted during the nine months ended March 31, 2023 and 2022, the assumptions used in the Monte Carlo simulation valuations were as follows:


	Nine Months Ended
	March 31,
	2023		2022
Weighted average fair value of performance-based awards granted	$	6.52	$	3.10
Risk-free interest rate		3.91% to 4.51%		0.53% to 0.60%
Expected term in years		2.36 to 2.78		2.64 to 2.79
Expected volatility		56.5% to 70.9%		64.7%
Dividend yield		6.1% to 7.8%		4.8% to 6.3%

Unvested restricted stock awards as of March 31, 2023 consisted of the following:


		Weighted
	Number of	Average
	Restricted	Grant-Date
Award Type	Shares	Fair Value
Time-vested awards	465,541	$	6.63
Performance-based awards	192,789		5.30
Unvested at March 31, 2023	658,330	$	6.24

The following table sets forth the restricted stock transactions for the nine months ended March 31, 2023:


						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, 2022	341,211		4.54	$	1,092	2.1
Time-vested shares granted	376,015		7.18
Performance-based shares granted	100,239		7.39
Vested	(133,515)		5.37
Forfeited	(25,620)		6.51
Unvested at March 31, 2023	658,330	$	6.24	$	3,279	2.5

Unvested contingent restricted stock units table below consists solely of performance-based awards for the nine months ended March 31, 2023:


						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, 2022	50,062		2.21	$	68	1.7
Performance-based awards granted	50,123		4.79
Vested	—		—
Forfeited	(3,787)		3.69
Expired	—		—
Unvested at March 31, 2023	96,398	$	3.49	$	227	2.1

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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,
	2023		2022		2023		2022
Numerator
Net income (loss)	$	13,957	$	5,705	$	35,051	$	17,756
Undistributed earnings allocated to unvested restricted stock		(253)		(113)		(515)		(359)
Net income (loss) for earnings per share calculation	$	13,704	$	5,592	$	34,536	$	17,397

Denominator
Weighted average number of common shares outstanding — Basic		33,013		33,009		33,108		32,933
Effect of dilutive securities:
Unvested restricted stock awards		143		379		178		325
Unvested contingent restricted stock units		—		—		5		—
Weighted average number of common shares and dilutive potential common shares used in diluted earnings per share		33,156		33,388		33,291		33,258

Net income (loss) per common share — Basic	$	0.42	$	0.17	$	1.04	$	0.53
Net income (loss) per common share — Diluted	$	0.41	$	0.17	$	1.04	$	0.52

Unvested restricted stock awards (both time-vested and performance-based), totaling approximately 262,000 and 120,000 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.

Unvested restricted stock awards (time-vested), totaling approximately 24,000 and 17,000 for the nine months ended March 31, 2022 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, 2023		June 30, 2022
Prepaid expenses and other current assets:
Receivable for settlement proceeds from acquisitions⁽¹⁾	$	—	$	2,263
Receivable for settlements on derivative contracts		211		—
Other receivables		7		37
Prepaid insurance		341		743
Prepaid federal and state income taxes		956		8
Prepaid subscription and licenses		59		38
Carryback of EOR tax credit		347		347
Prepaid other		844		439
Total prepaid expenses and other current assets	$	2,765	$	3,875

Other assets:
Deposit	$	1,158	$	1,150
Right of use asset under operating lease		195		21
Total other assets	$	1,353	$	1,171

Accrued liabilities and other:
Accrued payables	$	6,013	$	8,070
Accrued capital expenditures		454		—
Accrued incentive and other compensation		694		626
Accrued royalties payable		1,877		1,517
Accrued taxes other than income		118		178
Accrued severance		163		332
Accrued settlements on derivative contracts		—		919
Operating lease liability		59		26
Asset retirement obligations due within one year		51		22
Accrued - other		—		203
Total accrued liabilities and other	$	9,429	$	11,893

(1)	Receivables as of June 30, 2022 related to customary purchase adjustments of $1.6 million and $0.7 million related to the Jonah Field Acquisition and Williston Basin Acquisition, respectively. See Note 3, “Acquisitions” for a further discussion.

Note 14. Leases

Operating leases are reflected as an operating lease right of use (“ROU”) asset included in “Other assets”, and as a ROU liability in “Accrued liabilities and other” and “Operating lease liability” on the Company’s unaudited condensed consolidated balance sheets. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset would also include any lease payments made to the lessor prior to lease commencement less any lease incentives and initial direct costs incurred, if any. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term and are presented as “General and administrative expenses” in the unaudited condensed consolidated statements of operations. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. For all operating leases, lease and non-lease components are accounted for as a single lease component.

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As a non-operator and having adequate liquidity, the Company has generally not entered into lease transactions. The Company’s only operating lease is for corporate office space in Houston, Texas, effective May 1, 2019 and amended November 30, 2022 and set to expire September 30, 2026. The Company has no leases that meet the criteria for classification as a finance lease or a short-term lease.

The Company makes certain assumptions and judgments when evaluating a contract that meets the definition of a lease under ASC 842, Leases. As the Company’s operating lease did not provide an implicit rate, an incremental borrowing rate was calculated using information available at the commencement date of the lease. The incremental borrowing rate for a lease is the rate of interest for which the Company would pay on a collateralized basis to borrow an amount equal to the lease payments under similar terms. The lease term was determined by considering any option available to extend or to early terminate the lease which the Company believed was reasonably certain to be exercised.

The table below summarized the Company’s leases for the nine months ended March 31, 2023 and 2022 (in thousands, except years and discount rate):


	Nine Months Ended March 31,
	2023			2022
Statements of Operations:
Operating lease costs	$	42		$	39
Variable lease costs		27			28
Total lease costs	$	69		$	67

Statements of Cash Flow:
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	46		$	46

Other:
ROU assets obtained in exchange for new operating lease liabilities	$	212		$	—
Weighted average remaining lease term in years		3.42			0.67
Weighted average discount rate		6.44	%		5.15	%

The following table presents the Company’s ROU assets and lease liabilities (in thousands):


	March 31, 2023		June 30, 2022
Balance Sheets:
Operating lease ROU asset (included in other assets)	$	195	$	21
Accrued liabilities and other - current		59		26
Operating lease liability - long-term		137		—

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As of March 31, 2023, the future minimum lease payments associated with the Company’s non-cancellable operating lease for office space are as follows (in thousands):


Fiscal Year	March 31, 2023
Remaining in 2023	$	15
2024		61
2025		62
2026		64
2027		16
Thereafter		—
Total operating lease payments		218
Less: discount to present value		(22)
Total operating lease liabilities		196
Less: current operating lease liabilities		59
Non current operating lease liabilities	$	137

Note 15. Subsequent Events

Dividend Declaration

On May 8, 2023, the Company declared a quarterly cash dividend of $0.120 per share of common stock to shareholders of record on June 15, 2023 and payable on June 30, 2023.

Senior Secured Credit Facility

On May 5, 2023, the Company entered into the Tenth Amendment to the Senior Secured Credit Facility. This amendment, among other things, extends the maturity of the Senior Secured Credit Facility to April 9, 2026, converts the benchmark interest rate from LIBOR to SOFR plus a credit spread adjustment of 0.05%, and modifies the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, to $95.0 million.

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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, 2023, our third quarter of fiscal year 2023.

“Year-ago quarter” refers to the three months ended March 31, 2022, our third quarter of fiscal year 2022.

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 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 interests in the Jonah Field, a natural gas and natural gas liquids producing property in Sublette County, Wyoming, consist of an approximately 20% average net working interest with an associated 15% average net revenue interest in 595 producing wells and 950 net acres. The properties are operated by Jonah Energy (“Jonah”), an established operator in the region.

Our interests in the Williston Basin, producing oil and natural gas properties, consist of an approximately 39% average net working interest with an associated 33% average net revenue interest in 73 producing wells located on approximately 45,000 net acres (approximately 90% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota. The properties are primarily operated by Foundation Energy Management (“Foundation”), an established operator in the region.

Our interests in the Barnett Shale, natural gas and natural gas liquids producing properties, consist of an approximately 17% average net working interest with an associated 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 properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by seven other operators.

Our interests in the Hamilton Dome Field, a secondary oil recovery field utilizing water injection wells to pressurize the reservoir, consist of an 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 (“Merit”), who owns the vast 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.

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Our interests in the Delhi Field, a CO₂-EOR project, 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”). 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

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, extends the maturity of our Senior Secured Credit Facility to April 9, 2026, converts our benchmark interest rate from London Interbank Offered Rate (LIBOR) to a Secured Overnight Financing Rate (SOFR) plus a credit spread adjustment of 0.05%, and modifies the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, to $95.0 million.

Appointment of Chief Operating Officer

On February 23, 2023, we announced that the Board of Directors appointed J. Mark Bunch as Chief Operating Officer (“COO”). Mr. Bunch had been providing consulting services to the Company since 2016. We entered into an offer letter with Mr. Bunch setting forth his compensation as COO on February 21, 2023.

Appointment of Chief Executive Officer

On October 27, 2022, we announced that the Board of Directors selected Kelly W. Loyd as President and Chief Executive Officer (“CEO”). Mr. Loyd had been serving as Interim CEO since June 2022 and has served as a member of the Board of Directors since 2008. We entered into an offer letter with Mr. Loyd setting forth his compensation as CEO on October 25, 2022. Upon commencing employment, Mr. Loyd no longer receives compensation for his services as a member of the Board of Directors.

Share Repurchase Program

On September 8, 2022, the Board of Directors approved a share repurchase program under which we are authorized to repurchase up to $25.0 million of our common stock through December 31, 2024. We intend to fund repurchases from available 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 and 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 our shares, the market price of our common stock, our capital needs and resources, general market and economic conditions, and applicable legal requirements. The value of shares authorized for repurchase by our Board of Directors does not require us 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.

Once we completed repayment of borrowings on our Senior Secured Credit Facility and emerged from our blackout period in December 2022, 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 included a 30-day cooling off period that did not allow repurchases to commence until January 2023. The plan is effective until June 30, 2023, unless extended or renewed, and has a maximum authorized amount of $5.0 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 the repurchase program. During the three months ended March 31, 2023, 0.6 million shares of our common stock were repurchased

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under the plan at a total cost of approximately $3.9 million, including incremental direct transaction costs. These treasury shares were subsequently cancelled.

Highlights and Operations Update

●

Generated revenue of $36.9 million and net income of $14.0 million.

●

Production averaged 7,089 net barrels of oil equivalent per day (“BOEPD”).

●

Returned to shareholders $12.1 million in cash dividends during the nine months ended March 31, 2023 while repaying $21.3 million of borrowings on our Senior Secured Credit Facility incurred in calendar 2022 to acquire our Williston Basin and Jonah Field properties. We have paid out to shareholders more than $98.4 million in cash dividends since inception of the dividend program in December 2013.

●

Purchased 0.6 million shares of common stock for approximately $3.9 million under our repurchase program.

●

Continued to fund all operations, development capital expenditures, dividends and repurchase of shares out of operating cash flow.

●

Ended the third quarter of fiscal 2023 with $18.4 million in cash and cash equivalents and no outstanding borrowings under our Senior Secured Credit Facility.

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 started to recover primarily as a result of the roll-out of the COVID-19 vaccine and lessening of pandemic related government restrictions on individuals and businesses. In addition, 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 further enhanced volatility in global commodity prices in the first half of 2022.

Additionally, during the quarter ended March 31, 2023, the closures of Silicon Valley Bank and Signature Bank and their placement into receivership with the Federal Deposit Insurance Corporation (FDIC) created broad uncertainty around world-wide financial institutions and liquidity risk. While we do not have exposure to these banks, we do maintain cash balances in excess of FDIC insurance protections at banks we believe 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.

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; 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.

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Liquidity and Capital Resources

As of March 31, 2023, we had no borrowings outstanding on our Senior Secured Credit Facility and $18.4 million in cash and cash equivalents compared to $21.3 million of borrowings drawn on our Senior Secured Credit Facility and $8.3 million in cash and cash equivalents at June 30, 2022. Our primary sources of liquidity and capital resources during the nine months ended March 31, 2023 were cash provided by operations and the unused portion of our credit facility. Our primary uses of liquidity and capital resources for the nine months ended March 31, 2023 were repayments on our Senior Secured Credit Facility, cash dividend payments to our common stockholders, common stock repurchases, and capital expenditures on our existing oil and natural gas properties. As of March 31, 2023, working capital was $10.7 million, an increase of $4.6 million from working capital of $6.1 million as of June 30, 2022.

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. 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 LIBOR plus 2.75% or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%. On May 5, 2023, our benchmark interest rate was converted to SOFR plus 2.80%, which includes a 0.05% credit spread adjustment from LIBOR. For the nine months ended March 31, 2023, the weighted average interest on our borrowings was 5.25%. 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, 2023, 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, extends the maturity of our Senior Secured Credit Facility to April 9, 2026, converts our benchmark interest rate from LIBOR to SOFR plus a credit spread adjustment of 0.05%, and modifies the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, to $95.0 million.

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 amended above, to the extent it exceeds the borrowing base then in effect. This amendment also required us to enter into hedges for the 12-month period ending February 2023, covering 25% of expected 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 certain amount of our 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 Ninth Amendment, as discussed above.

On August 5, 2021, we entered into the Seventh Amendment of our Senior Secured Credit Facility which, among other things, added definitions for the terms “Acquired Entity or Mineral Interests” and “Acquired Entity or Mineral Interests EBITDA Adjustment.” Additionally, the consolidated tangible net worth covenant level was reduced to $40.0 million from $50.0 million.

We have historically funded operations through cash from operations and working capital. Our primary source of cash 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 development activities for our properties with cash flows from operating activities and existing working capital.

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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 $50.0 million as of March 31, 2023. 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 38 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. In light of our improving financial performance and industry outlook, the Board of Directors has increased the dividend rate over the past two years, with the most recent increase occurring on September 12, 2022, when the Board of Directors declared a dividend of $0.12 per share that was paid on September 30, 2022. On May 8, 2023, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on June 15, 2023 and payable on June 30, 2023.

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 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 complimentary to the existing dividend policy and is a tax efficient means to further improve shareholder return.

Once we completed the repayment of borrowings on our Senior Secured Credit Facility and emerged from our blackout period in December 2022, 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 included a 30-day cooling off period that did not allow repurchases to commence until January 2023. The plan is effective until June 30, 2023, unless extended, renewed or terminated, and has a maximum authorized amount of $5.0 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 the repurchase program. During the three 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 treasury shares were subsequently cancelled.

Capital Expenditures

During the nine months ended March 31, 2023, we incurred $4.4 million on development capital expenditures and $0.1 million for plugging and abandoning costs in the Jonah Field, Williston Basin, Barnett Shale and Hamilton Dome Field. During the current quarter, we participated in the completion and fracture stimulation of a vertical Bakken well and are waiting on results.

Based on discussions with our operators, we expect capital workover projects to continue in all the fields. Overall, for fiscal year 2023, we expect budgeted capital expenditures to be in the range of $6.0 million to $7.0 million, which excludes any potential acquisitions. These expenditures include anticipated capital costs at Delhi field for an NGL plant heat exchanger project, projected to improve operational efficiency throughout the year, which is currently underway and expected to be online before our fiscal year-end. As of March 31, 2023, we have incurred approximately $0.6 million related to this project. Our expected capital expenditures for fiscal year 2023 also include participating in another vertical recompletion in the Williston Basin. The timing of the two sidetrack locations targeting the Birdbear formation has been pushed to fiscal year 2024 due to delays in obtaining pooling and spacing orders with the state of North Dakota. We anticipate this permitting to be completed in the first fiscal quarter of 2024.

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

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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, 2023 were $91.38 per barrel of oil, $5.97 per MMBtu of natural gas and $47.07 per barrel of NGLs. As of March 31, 2023, 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, 2023 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. Using the April 2023 West Texas Intermediate (“WTI”) price of $75.68 per barrel of oil and the Henry Hub price of $2.10 per MMBtu of natural gas and holding these prices constant for two months to create a trailing 12-month period of average prices that is more reflective of recent price trends, our ceiling test calculation would not have generated an impairment, holding all other inputs and factors constant.

Overview of Cash Flow Activities


	Nine Months Ended March 31,
	2023		2022		Change
Cash flows provided by operating activities	$	51,719	$	28,691	$	23,028
Cash flows used in investing activities		(4,265)		(28,140)		23,875
Cash flows (used in) provided by financing activities		(37,347)		7,541		(44,888)
Net increase in cash and cash equivalents	$	10,107	$	8,092	$	2,015

Cash provided by operating activities for the nine months ended March 31, 2023 increased $23.0 million from the nine months ended March 31, 2022 primarily due to an increase in revenues. Total revenues increased $43.4 million as compared to the prior year period driven by an increase in our average realized price per barrel of oil equivalent (“BOE”) and an increase in our average daily production primarily due to our acquisition of non-operated working interests in the Williston Basin and Jonah Field in January 2022 and April 2022, respectively.

Cash used in investing activities for the nine months ended March 31, 2023 decreased $23.9 million from the nine months ended March 31, 2022 primarily due the $25.7 million acquisition of our Williston Basin properties in January 2022 and a $1.5 million deposit made in February 2022 for our acquisition in the Jonah Field partially offset by an increase in development capital expenditures in the current fiscal year.

Net cash flows used in financing activities for the nine months ended March 31, 2023 were $37.3 million which included the repayment of $21.3 million of borrowings outstanding under our Senior Secured Credit Facility, $12.1 million in dividends paid to our common stockholders, and $3.9 million paid to repurchase shares of common stock under our share repurchase program. Net cash flows provided by financing activities for the nine months ended March 31, 2022 were $7.5 million which primarily included $16.0 million in net borrowings under our Senior Secured Credit Facility offset by $8.4 million in dividends paid to our common stockholders.

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Results of Operations

Three Months Ended March 31, 2023 and 2022

We reported net income of $14.0 million and $5.7 million for the three months ended March 31, 2023 and 2022, 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)	2023		2022			Variance		Variance %
Net income (loss)	$	13,957	$	5,705		$	8,252	144.6	%
Revenues:
Crude oil		11,799		14,868			(3,069)	(20.6)	%
Natural gas		21,598		6,070			15,528	255.8	%
Natural gas liquids		3,470		4,750			(1,280)	(26.9)	%
Total revenues		36,867		25,688			11,179	43.5	%
Operating costs:
Lease operating costs:
CO₂ costs		1,821		2,321			(500)	(21.5)	%
Ad valorem and production taxes		1,642		1,449			193	13.3	%
Other lease operating costs		10,107		8,314			1,793	21.6	%
Depletion, depreciation, and accretion:					��
Depletion of full cost proved oil and natural gas properties		3,098		1,602			1,496	93.4	%
Accretion of asset retirement obligations		285		135			150	111.1	%
General and administrative expenses:
General and administrative		1,814		1,175			639	54.4	%
Stock-based compensation		453		340			113	33.2	%
Other income (expense):
Net gain (loss) on derivative contracts		270		(2,591)			2,861	(110.4)	%
Interest and other income		13		2			11	550.0	%
Interest expense		(32)		(170)			138	(81.2)	%
Income tax (expense) benefit		(3,941)		(1,888)			(2,053)	108.7	%

Production:
Crude oil (MBBL)		167		163			4	2.5	%
Natural gas (MMCF)		2,204		1,429			775	54.2	%
Natural gas liquids (MBBL)		104		100			4	4.0	%
Equivalent (MBOE)⁽¹⁾		638		501			137	27.3	%
Average daily production (BOEPD)⁽¹⁾		7,089		5,567			1,522	27.3	%

Average price per unit⁽²⁾:
Crude oil (BBL)	$	70.65	$	91.21		$	(20.56)	(22.5)	%
Natural gas (MCF)		9.80		4.25			5.55	130.6	%
Natural Gas Liquids (BBL)		33.37		47.50			(14.13)	(29.7)	%
Equivalent (BOE)⁽¹⁾		57.79		51.27			6.52	12.7	%

Average cost per unit:
Operating costs:
Lease operating costs:
CO₂ costs	$	2.85	$	4.63			(1.78)	(38.4)	%
Ad valorem and production taxes		2.57		2.89			(0.32)	(11.1)	%
Other lease operating costs		15.84		16.59			(0.75)	(4.5)	%
Depletion of full cost proved oil and natural gas properties		4.86		3.20			1.66	51.9	%
General and administrative expenses:
General and administrative		2.84		2.35			0.49	20.9	%
Stock-based compensation		0.71		0.68			0.03	4.4	%

(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 $36.9 million and $25.7 million for the three months ended March 31, 2023 and 2022, respectively. The increase in revenue is primarily due to an increase in production coupled with an increase in our average realized price per BOE. Average daily equivalent production increased 27.3% from 5,567 BOEPD to 7,089 BOEPD due to the acquisitions of non-operated working interests in the Jonah Field and Williston Basin in the second half of fiscal year 2022, which collectively increased current quarter production by approximately 1,913 BOEPD. In total, our average realized commodity price (excluding the impact of derivative contracts) increased approximately $6.52 per BOE, or 12.7%, over the year-ago quarter, primarily due to 130.6% increase in our realized natural gas prices from the year-ago quarter. This was attributed to the 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 for the current quarter. This increase was offset by decreases in realized crude oil and NGL prices of 22.5% and 29.7%, respectively, from the year-ago quarter, primarily as a result of the decline in WTI pricing.

Lease Operating Costs

Ad valorem and production taxes were $1.6 million and $1.4 million for the three months ended March 31, 2023 and 2022, respectively. The increase in taxes is primarily due to increased production volumes and the increase in natural gas pricing described above as production taxes are based on sales at the wellhead. On a per unit basis, ad valorem and production taxes were $2.57 per BOE and $2.89 per BOE for the three months ended March 31, 2023 and 2022, respectively. The decrease on a per BOE basis is due to an increase in production volumes related to our acquisition of interests in the Williston Basin where we do not incur Ad valorem taxes.

The following table summarizes CO₂costs per MCF and CO₂volumes for the three months ended March 31, 2023 and 2022. 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,
	2023		2022		Variance		Variance %
CO₂ costs per MCF	$	0.92	$	1.12	$	(0.20)	(17.9)	%
CO₂ volumes (MMCF per day, gross)		91.7		96.0		(4.3)	(4.5)	%

The $0.5 million decrease in CO₂costs for the current quarter was primarily due to a 17.9% decrease in CO₂ costs per MCF, which was driven by a decrease in our average realized oil price in addition to a 4.5% decrease in purchased CO₂volumes. In the current quarter, the decrease in volumes is due to Denbury’s reduced allocation of CO₂ to the Delhi Field. 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 $2.85 per BOE and $4.63 per BOE for the three months ended March 31, 2023 and 2022, respectively. This decrease was due to the aforementioned decrease in the average realized oil price in the field as well as an increase in our total production since the year-ago quarter due to our acquisitions in the Jonah Field and Williston Basin in the second half of fiscal year 2022.

Other lease operating costs included remedial workover costs and gathering and transportation costs for our oil and natural gas production. Compared to the year-ago quarter, other lease operating costs increased approximately $1.8 million, or 21.6% in the current quarter primarily due to our acquisitions in the Jonah Field and Williston Basin in April 2022 and January 2022, respectively. Other lease operating costs on a per BOE basis decreased to $15.84 per BOE from $16.59 per BOE in the year-ago quarter.

Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased $1.5 million or 93.4% from the year-ago quarter of $1.6 million to $3.1 million for the current quarter primarily due to an increase in production. On a per unit basis, depletion expense was $4.86 per BOE and $3.20 per BOE for the three months ended March 31, 2023 and 2022, respectively. The depletable base of our unit of

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production calculation increased due to our acquisitions in fiscal year 2022 and increases in our future development costs associated with our proved undeveloped reserve additions at fiscal year-end 2022. These increases were partially offset by an increase in proved reserve volumes.

General and Administrative Expenses

General and administrative expenses for the current quarter increased $0.6 million, or 54.4%, to $1.8 million compared to $1.2 million for the year-ago quarter. The increase is primarily due to approximately $0.3 million for salary and employee benefits due to additional personnel and $0.2 million for professional fees related to accounting and audit-related services.

Stock-based Compensation Expense

Stock-based compensation expense for the current quarter increased $0.1 million, or 33.2%, to $0.5 million compared to $0.3 million for the year-ago quarter. The increase is primarily due to the addition of new personnel, including our new COO, and the associated new awards granted during the current year period.

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 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 subsequent decline in commodity prices resulted in a realized loss on derivative contracts for the year-ago quarter and a realized gain on derivative assets for the current quarter. As of March 31, 2023, we did not have any open crude oil or natural gas derivative contracts.


	Three Months Ended
	March 31,
(in thousands, except per unit and per BOE amounts)	2023		2022		Variance		Variance %
Realized gain (loss) on derivative contracts	$	465	$	(193)	$	658	(340.9)	%
Unrealized gain (loss) on derivative contracts		(195)		(2,398)		2,203	(91.9)	%
Total net gain (loss) on derivative contracts	$	270	$	(2,591)	$	2,861	(110.4)	%

Average realized crude oil price per BBL	$	70.65	$	91.21	$	(20.56)	(22.5)	%
Cash effect of oil derivative contracts per BBL		—		(1.18)		1.18	(100.0)	%
Crude oil price per Bbl (including impact of realized derivatives)	$	70.65	$	90.03	$	(19.38)	(21.5)	%

Average realized natural gas price per MCF	$	9.80	$	4.25	$	5.55	130.6	%
Cash effect of natural gas derivative contracts per MCF		0.21		—		0.21	—	%
Natural gas price per Mcf (including impact of realized derivatives)	$	10.01	$	4.25	$	5.76	135.5	%

Interest Expense

Interest expense decreased $0.1 million compared to the year-ago quarter primarily due to no borrowings outstanding on our Senior Secured Credit Facility during the current quarter.

Income Tax (Expense) Benefit

For the three months ended March 31, 2023, we recognized income tax expense of $3.9 million on net income before income taxes of $17.9 million compared to income tax expense of $1.9 million on net income before income taxes of $7.6 million for the three months ended March 31, 2022. Our effective tax rates for current quarter is 22.0% compared to 24.9% in the year-ago quarter.

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Nine Months Ended March 31, 2023 and 2022

We reported net income of $35.1 million and $17.8 million for the nine months ended March 31, 2023 and 2022, 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)	2023		2022		Variance		Variance %
Net income (loss)	$	35,051	$	17,756	$	17,295	97.4	%
Revenues:
Crude oil		40,062		34,309		5,753	16.8	%
Natural gas		58,816		20,698		38,118	184.2	%
Natural gas liquids		11,462		11,899		(437)	(3.7)	%
Total revenues		110,340		66,906		43,434	64.9	%
Operating costs:
Lease operating costs:
CO₂ costs		6,027		5,135		892	17.4	%
Ad valorem and production taxes		7,001		3,968		3,033	76.4	%
Other lease operating costs		34,699		22,277		12,422	55.8	%
Depletion, depreciation, and accretion:
Depletion of full cost proved oil and natural gas properties		9,598		4,146		5,452	131.5	%
Depreciation of other property and equipment		—		4		(4)	(100.0)	%
Accretion of asset retirement obligations		841		339		502	148.1	%
General and administrative expenses:
General and administrative		6,165		4,410		1,755	39.8	%
Stock-based compensation		1,155		868		287	33.1	%
Other income (expense):
Net gain (loss) on derivative contracts		513		(2,591)		3,104	(119.8)	%
Interest and other income		26		12		14	116.7	%
Interest expense		(404)		(272)		(132)	48.5	%
Income tax (expense) benefit		(9,938)		(5,152)		(4,786)	92.9	%

Production:
Crude oil (MBBL)		501		447		54	12.1	%
Natural gas (MMCF)		7,065		4,728		2,337	49.4	%
Natural gas liquids (MBBL)		325		260		65	25.0	%
Equivalent (MBOE)⁽¹⁾		2,004		1,495		509	34.0	%
Average daily production (BOEPD)⁽¹⁾		7,314		5,456		1,858	34.1	%

Average price per unit⁽²⁾:
Crude oil (BBL)	$	79.96	$	76.75	$	3.21	4.2	%
Natural gas (MCF)		8.32		4.38		3.94	90.0	%
Natural Gas Liquids (BBL)		35.27		45.77		(10.50)	(22.9)	%
Equivalent (BOE)⁽¹⁾		55.06		44.75		10.31	23.0	%

Average cost per unit:
Operating costs:
Lease operating costs:
CO₂ costs	$	3.01	$	3.43	��	(0.42)	(12.2)	%
Ad valorem and production taxes		3.49		2.65		0.84	31.7	%
Other lease operating costs		17.31		14.90		2.41	16.2	%
Depletion of full cost proved oil and natural gas properties		4.79		2.77		2.02	72.9	%
General and administrative expenses:
General and administrative		3.08		2.95		0.13	4.4	%
Stock-based compensation		0.58		0.58		—	—	%

(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 $110.3 million and $66.9 million for the nine months ended March 31, 2023 and 2022, respectively. The increase in revenue is primarily due to our acquisitions of non-operated working interests in the Jonah Field and Williston Basin in the second half of fiscal year 2022. Average daily equivalent production increased 34.1% from 5,456 BOEPD in the prior year period to 7,314 BOEPD in the current period. Production increases were driven by our acquisitions of non-operated working interests in the Jonah Field and Williston Basin in the second half of fiscal year 2022, which increased the current nine months ended production by approximately 2,253 BOEPD. Our average realized commodity price (excluding the impact of derivative contracts) for the nine months ended March 31, 2023 increased approximately $10.31 per BOE, or 23.0%, over the prior year period. Realized oil and natural gas prices increased approximately 4.2% and 90.0%, respectively, over the prior year period. The increase in realized natural gas prices is primarily attributed to the benefit of strong natural gas price differentials received at the Jonah Field where our realized price for natural gas for the current year period was $12.99 per MCF. This increase is offset by a 23% decrease in realized NGL prices from the prior year period.

Lease Operating Costs

Ad valorem and production taxes were $7.0 million and $4.0 million for the nine months ended March 31, 2023 and 2022, respectively. On a per unit basis, ad valorem and production taxes were $3.49 per BOE and $2.65 per BOE for the nine months ended March 31, 2023 and 2022, respectively. The increase in ad valorem and production taxes is primarily due to increases in oil and natural gas prices and increased 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, 2023 and 2022. 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,
	2023		2022		Variance		Variance %
CO₂ costs per MCF	$	1.01	$	0.99	$	0.02	2.0	%
CO₂ volumes (MMCF per day, gross)		90.8		79.6		11.2	14.1	%

The $0.9 million increase in CO₂costs for the nine months ended March 31, 2023 was primarily due to a 14.1% increase in purchased CO₂volumes combined with a 2.0% increase in CO₂ costs per MCF, which was driven by an increase in our average realized oil price. CO₂ purchases were temporarily suspended throughout the prior year period due to preventative maintenance on the pipeline that supplies newly purchased CO₂ to the Delhi Field. Additionally, CO₂ purchase nominations increased from the prior year period 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 $3.01 per BOE and $3.43 per BOE for the nine months ended March 31, 2023 and 2022, respectively. The decrease on a per BOE basis is due to the increase in total production since the prior year period, from our acquisitions in the Jonah Field and Williston Basin in the second half of fiscal year 2022.

Other lease operating costs include remedial workover costs and gathering and transportation costs for our oil and natural gas production. Compared to the prior year period, other lease operating costs increased 55.8% in the nine months ended March 31, 2023 primarily due to the acquisitions in the Jonah Field and Williston Basin in April 2022 and January 2022, respectively. Discussed further below, other lease operating costs on a per BOE basis increased to $17.31 per BOE from $14.90 per BOE in the year-ago quarter. Other lease operating costs per BOE for our Jonah Field were approximately $10.69 per BOE for the nine months ended March 31, 2023. Other lease operating costs per BOE for the Williston Basin were approximately $26.34 per BOE for the nine months ended March 31, 2023, an increase of approximately $6.11 per BOE from the prior year period, primarily as a result of increased remedial workovers. Other lease operating costs per BOE for the Barnett Shale were approximately $17.77 for the nine months ended March 31, 2023, an increase of approximately $4.50 per BOE from the prior year period, due to higher gathering, transportation and other expenses as a result of higher commodity prices through the first half of fiscal year 2023.

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Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased $5.5 million or 131.5% from $4.1 million to $9.6 million for the nine months ended March 31, 2023 primarily due to an increase in production. On a per unit basis, depletion expense was $4.79 per BOE and $2.77 per BOE for the nine months ended March 31, 2023 and 2022, respectively. The depletable base of our unit of production calculation increased due to our acquisitions in fiscal year 2022 and increases in our future development costs associated with our proved undeveloped reserve additions at fiscal year-end 2022. These increases were partially offset by an increase in proved reserve volumes.

General and Administrative Expenses

General and administrative expenses for the nine months ended March 31, 2023 increased $1.8 million, or 39.8%, to $6.2 million compared to $4.4 million for the prior year period. The increase is primarily due to approximately $0.7 million for salary and employee benefits due to additional personnel added since the prior year period and $0.3 million in professional fees associated with our search for a CEO. The remaining increase is associated with fees for accounting and audit-related services and public reporting expenses.

Stock-based Compensation Expense

Stock-based compensation expense for the nine months ended March 31, 2023 increased $0.3 million, or 33.1%, to $1.2 million compared to $0.9 million for the prior year period. The increase is primarily due to the addition of new personnel, including our new COO, and the associated new awards granted during the current year period. Approximately $0.1 million of the current year period increase related to a one-time share award granted in November 2022, which vested and was fully expensed immediately.

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 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 resulted in realized losses on derivative contracts for the current year and prior year periods. As of March 31, 2023, we did not have any open crude oil or natural gas derivative contracts.


	Nine Months Ended
	March 31,
(in thousands, except per unit and per BOE amounts)	2023		2022		Variance		Variance %
Realized gain (loss) on derivative contracts	$	(1,481)	$	(193)	$	(1,288)	667.4	%
Unrealized gain (loss) on derivative contracts		1,994		(2,398)		4,392	(183.2)	%
Total net gain (loss) on derivative contracts	$	513	$	(2,591)	$	3,104	(119.8)	%

Average realized crude oil price per BBL	$	79.96	$	76.75	$	3.21	4.2	%
Cash effect of oil derivative contracts per BBL		(0.49)		(0.43)		(0.06)	14.0	%
Crude oil price per Bbl (including impact of realized derivatives)	$	79.47	$	76.32	$	3.15	4.1	%

Average realized natural gas price per MCF	$	8.32	$	4.38	$	3.94	90.0	%
Cash effect of natural gas derivative contracts per MCF		(0.17)		—		(0.17)	—	%
Natural gas price per Mcf (including impact of realized derivatives)	$	8.15	$	4.38	$	3.77	86.1	%

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Interest Expense

Interest expense increased $0.1 million for the nine months ended March 31, 2023 compared to the prior year period primarily due to increased borrowings outstanding on our Senior Secured Credit Facility used to acquire interests in the Williston Basin and Jonah Field during the second half of fiscal year 2022.

Income Tax (Expense) Benefit

For the nine months ended March 31, 2023, we recognized income tax expense of $9.9 million on net income before income taxes of $45.0 million compared to income tax expense of $5.2 million on net income before income taxes of $22.9 million for the nine months ended March 31, 2022. The effective tax rates were 22.1% and 22.5% for nine months ended March 31, 2023 and 2022, respectively.

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 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, 2022.

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.

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 2023 and 2022, 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.

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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 and that such 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, 2023 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.

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, 2023, 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 controls 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.

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Item 1A. Risk Factors

Our Annual Report on Form 10-K for the year ended June 30, 2022 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, 2023.


				(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 2023	80,733	$	6.46	80,733	$	24,479
February 2023	255,981		6.32	252,125		22,885
March 2023	301,672		5.76	300,931		21,152

(1)	During the three months ended March 31, 2023, 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 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, our 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 December 2022, 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 included a 30-day cooling off period that did not allow repurchases to commence until January 2023. The plan is effective until June 30, 2023, unless extended, renewed or terminated by the Company, and has a maximum authorized amount of $5.0 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.

Item 3. Defaults Upon Senior Securities

Not Applicable.

Item 4. Mine Safety Disclosures

Not Applicable.

Item 5. Other Information

None.

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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).
3.2		Amended Bylaws (incorporated by reference to Exhibit 2.1 of our Annual Report on Form 10-KSB filed March 31, 2004)
10.2.10*		Tenth Amendment to the Credit Agreement dated May 5, 2023, between Evolution Petroleum Corporation and MidFirst Bank
10.10†*		Employment Offer Letter to J. Mark Bunch dated February 21, 2023.
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.

† Indicates management contract or compensatory plan or arrangement.

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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 10, 2023	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

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Evolution Petroleum (EPM) 10-Q2023 Q3 Quarterly report

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