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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

​

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

​

For the quarterly period ended December 31, 2023

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

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For the transition period from to

Commission File Number 001-32942

EVOLUTION PETROLEUM CORP ORATION

(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.

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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
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 February 2, 2024, 33,456,330 shares of the Registrant’s Common Stock, $0.001 par value per share, were outstanding.

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Table of Contents

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 December 31, 2023 and June 30, 2023 | 4
​ | Condensed Consolidated Statements of Operations (Unaudited) for the three and six months ended December 31, 2023 and 2022 | 5
​ | Condensed Consolidated Statements of Cash Flows (Unaudited) for the six months ended December 31, 2023 and 2022 | 6
​ | Condensed Consolidated Statements of Changes in Stockholders’ Equity (Unaudited) for the three and six months ended December 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 | 23
Item 3. | Quantitative and Qualitative Disclosures about Market Risks | 37
Item 4. | Controls and Procedures | 37
PART II. OTHER INFORMATION | 38
Item 1. | Legal Proceedings | 38
Item 1A. | Risk Factors | 38
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.

​

1

Table of Contents

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;

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

| ● | anticipated oil, natural gas and NGL prices;

| ● | anticipated drilling and completions activity;

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

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

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

| ● | future interest expense;

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

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

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

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

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

| ● | adequacy of provisions for abandonment and site reclamation costs;

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

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

| ● | the adequacy of our provision for taxes and legal claims;

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

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

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

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

| ● | adverse weather events;

| ● | anticipated staffing levels;

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

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

​

2

Table of Contents

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

| ● | future commodity prices and basis differentials;

| ● | our ability to access credit facilities and shelf prospectuses;

| ● | assumptions contained in our corporate guidance;

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

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

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

| ● | assumed tax, royalty and regulatory regimes;

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

| ● | the other assumptions contained herein.

​

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

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

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

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3

Table of Contents

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)

​

​

​ | ​ | ​ | ​ | ​ | ​ | ​
​ |  | December 31, 2023 |  | June 30, 2023
Assets | ​ | ​ |  | ​ | ​ |
Current assets | ​ | ​ |  | ​ | ​ |
Cash and cash equivalents | ​ | $ | 8,460 | ​ | $ | 11,034
Receivables from crude oil, natural gas, and natural gas liquids revenues | ​ | ​ | 10,119 | ​ | ​ | 7,884
Prepaid expenses and other current assets | ​ | ​ | 2,569 | ​ | ​ | 2,277
Total current assets | ​ | ​ | 21,148 | ​ | ​ | 21,195
Property and equipment, net of depletion, depreciation, and impairment | ​ | ​ |  | ​ | ​ | ​
Oil and natural gas properties—full-cost method of accounting: | ​ | ​ | ​ | ​ | ​ | ​
Oil and natural gas properties, subject to amortization, net | ​ | ​ | 100,111 | ​ | ​ | 105,781
Oil and natural gas properties, not subject to amortization | ​ | ​ | 3,370 | ​ | ​ | —
Total property and equipment, net | ​ | ​ | 103,481 | ​ | ​ | 105,781
​ | ​ | ​ | ​ | ​ | ​ | ​
Other assets | ​ | ​ | 1,337 | ​ | ​ | 1,341
Total assets | ​ | $ | 125,966 | ​ | $ | 128,317
Liabilities and Stockholders' Equity | ​ | ​ |  | ​ | ​ | ​
Current liabilities | ​ | ​ |  | ​ | ​ | ​
Accounts payable | ​ | $ | 8,233 | ​ | $ | 5,891
Accrued liabilities and other | ​ | ​ | 6,294 | ​ | ​ | 6,027
State and federal taxes payable | ​ | ​ | — | ​ | ​ | 365
Total current liabilities | ​ | ​ | 14,527 | ​ | ​ | 12,283
Long term liabilities | ​ | ​ |  | ​ | ​ | ​
Deferred income taxes | ​ | ​ | 6,161 | ​ | ​ | 6,803
Asset retirement obligations | ​ | ​ | 17,738 | ​ | ​ | 17,012
Operating lease liability | ​ | ​ | 101 | ​ | ​ | 125
Total liabilities | ​ | ​ | 38,527 | ​ | ​ | 36,223
Commitments and contingencies (Note 9) | ​ | ​ | ​ | ​ | ​ | ​
Stockholders' equity | ​ | ​ |  | ​ | ​ | ​
Common stock; par value $0.001; 100,000,000 shares authorized: issued and | ​ | ​ | ​ | ​ | ​ | ​
outstanding 33,506,794 and 33,247,523 shares as of December 31, 2023 | ​ | ​ | ​ | ​ | ​ | ​
and June 30, 2023, respectively | ​ | ​ | 34 | ​ | ​ | 33
Additional paid-in capital | ​ | ​ | 40,920 | ​ | ​ | 40,098
Retained earnings | ​ | ​ | 46,485 | ​ | ​ | 51,963
Total stockholders' equity | ​ | ​ | 87,439 | ​ | ​ | 92,094
Total liabilities and stockholders' equity | ​ | $ | 125,966 | ​ | $ | 128,317

​

​

See accompanying notes to unaudited condensed consolidated financial statements.

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4

Table of Contents

EVOLUTION PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)

​

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
| ​ | Three Months Ended | ​ | Six Months Ended
​ | ​ | December 31, | ​ | December 31,
| ​ | 2023 | ​ | 2022 | ​ | 2023 |  | 2022
Revenues | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Crude oil | ​ | $ | 11,759 | ​ | $ | 13,100 | ​ | $ | 24,375 | ​ | $ | 28,263
Natural gas | ​ | ​ | 6,531 | ​ | ​ | 17,370 | ​ | ​ | 12,083 | ​ | ​ | 37,218
Natural gas liquids | ​ | ​ | 2,734 | ​ | ​ | 3,206 | ​ | ​ | 5,167 | ​ | ​ | 7,992
Total revenues | ​ | ​ | 21,024 | ​ | ​ | 33,676 | ​ | ​ | 41,625 | ​ | ​ | 73,473
Operating costs | ​ | ​ |  | ​ | ​ |  | ​ | ​ | ​ | ​ | ​ |
Lease operating costs | ​ | ​ | 12,358 | ​ | ​ | 15,041 | ​ | ​ | 24,241 | ​ | ​ | 34,157
Depletion, depreciation, and accretion | ​ | ​ | 4,598 | ​ | ​ | 3,458 | ​ | ​ | 8,860 | ​ | ​ | 7,056
General and administrative expenses | ​ | ​ | 2,502 | ​ | ​ | 2,581 | ​ | ​ | 5,105 | ​ | ​ | 5,053
Total operating costs | ​ | ​ | 19,458 | ​ | ​ | 21,080 | ​ | ​ | 38,206 | ​ | ​ | 46,266
Income (loss) from operations | ​ | ​ | 1,566 | ​ | ​ | 12,596 | ​ | ​ | 3,419 | ​ | ​ | 27,207
Other income (expense) | ​ | ​ |  | ​ | ​ |  | ​ | ​ | ​ | ​ | ​ |
Net gain (loss) on derivative contracts | ​ | ​ | — | ​ | ​ | 846 | ​ | ​ | — | ​ | ​ | 243
Interest and other income | ​ | ​ | 104 | ​ | ​ | 7 | ​ | ​ | 220 | ​ | ​ | 13
Interest expense | ​ | ​ | (34) | ​ | ​ | (129) | ​ | ​ | (66) | ​ | ​ | (372)
Income (loss) before income taxes | ​ | ​ | 1,636 | ​ | ​ | 13,320 | ​ | ​ | 3,573 | ​ | ​ | 27,091
Income tax (expense) benefit | ​ | ​ | (554) | ​ | ​ | (2,933) | ​ | ​ | (1,017) | ​ | ​ | (5,997)
Net income (loss) | ​ | $ | 1,082 | ​ | $ | 10,387 | ​ | $ | 2,556 | ​ | $ | 21,094
Net income (loss) per common share: | ​ | ​ |  | ​ | ​ |  | ​ | ​ |  | ​ | ​ |
Basic | ​ | $ | 0.03 | ​ | $ | 0.31 | ​ | $ | 0.08 | ​ | $ | 0.63
Diluted | ​ | $ | 0.03 | ​ | $ | 0.31 | ​ | $ | 0.08 | ​ | $ | 0.62
Weighted average number of common shares outstanding: | ​ | ​ |  | ​ | ​ |  | ​ | ​ |  | ​ | ​ |
Basic | ​ | ​ | 32,693 | ​ | ​ | 33,174 | ​ | ​ | 32,676 | ​ | ​ | 33,154
Diluted | ​ | ​ | 32,900 | ​ | ​ | 33,394 | ​ | ​ | 32,940 | ​ | ​ | 33,356

​

​

See accompanying notes to unaudited condensed consolidated financial statements.

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5

Table of Contents

EVOLUTION PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)

​

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Six Months Ended December 31,
|  | 2023 |  | 2022
Cash flows from operating activities: | ​ | ​ |  | ​ | ​ |
Net income (loss) | ​ | $ | 2,556 | ​ | $ | 21,094
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ​ | ​ |  | ​ | ​ | ​
Depletion, depreciation, and accretion | ​ | ​ | 8,860 | ​ | ​ | 7,056
Stock-based compensation | ​ | ​ | 1,036 | ​ | ​ | 702
Settlement of asset retirement obligations | ​ | ​ | — | ​ | ​ | (71)
Deferred income taxes | ​ | ​ | (642) | ​ | ​ | (355)
Unrealized (gain) loss on derivative contracts | ​ | ​ | — | ​ | ​ | (2,189)
Accrued settlements on derivative contracts | ​ | ​ | — | ​ | ​ | (919)
Other | ​ | ​ | 3 | ​ | ​ | (4)
Changes in operating assets and liabilities: | ​ | ​ |  | ​ | ​ | ​
Receivables from crude oil, natural gas, and natural gas liquids revenues | ​ | ​ | (2,239) | ​ | ​ | 8,113
Prepaid expenses and other current assets | ​ | ​ | (274) | ​ | ​ | (316)
Accounts payable and accrued liabilities | ​ | ​ | 2,443 | ​ | ​ | (5,398)
State and federal income taxes payable | ​ | ​ | (365) | ​ | ​ | 56
Net cash provided by operating activities | ​ | ​ | 11,378 | ​ | ​ | 27,769
Cash flows from investing activities: | ​ | ​ | ​ | ​ | ​ | ​
Acquisition of oil and natural gas properties | ​ | ​ | — | ​ | ​ | (31)
Capital expenditures for oil and natural gas properties | ​ | ​ | (5,705) | ​ | ​ | (2,886)
Net cash used in investing activities | ​ | ​ | (5,705) | ​ | ​ | (2,917)
Cash flows from financing activities: | ​ | ​ |  | ​ | ​ |
Common stock dividends paid | ​ | ​ | (8,034) | ​ | ​ | (8,085)
Common stock repurchases, including stock surrendered for tax withholding | ​ | ​ | (213) | ​ | ​ | (87)
Repayments of senior secured credit facility | ​ | ​ | — | ​ | ​ | (21,250)
Net cash (used in) provided by financing activities | ​ | ​ | (8,247) | ​ | ​ | (29,422)
Net increase (decrease) in cash and cash equivalents | ​ | ​ | (2,574) | ​ | ​ | (4,570)
Cash and cash equivalents, beginning of period | ​ | ​ | 11,034 | ​ | ​ | 8,280
Cash and cash equivalents, end of period | ​ | $ | 8,460 | ​ | $ | 3,710
​ | ​ | ​ | ​ | ​ | ​ | ​
Supplemental disclosures of cash flow information: | ​ | ​ | ​ | ​ | ​ | ​
Non-cash investing and financing transactions: | ​ | ​ | ​ | ​ | ​ | ​
Increase (decrease) in accrued capital expenditures for oil and natural gas properties | ​ | $ | (142) | ​ | $ | (768)

​

​

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 December 31, 2023 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balances at September 30, 2023 | ​ | 33,440 | ​ | $ | 33 | ​ | $ | 40,465 | ​ | $ | 49,424 | ​ | $ | — | ​ | $ | 89,922
Issuance of restricted common stock | ​ | 84 | ​ | ​ | 1 | ​ | ​ | (1) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Common stock repurchases, including stock surrendered for tax withholding | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (108) | ​ | ​ | (108)
Retirements of treasury stock | ​ | (17) | ​ | ​ | — | ​ | ​ | (108) | ​ | ​ | — | ​ | ​ | 108 | ​ | ​ | —
Stock-based compensation | ​ | — | ​ | ​ | — | ​ | ​ | 564 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 564
Net income (loss) | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 1,082 | ​ | ​ | — | ​ | ​ | 1,082
Common stock dividends paid | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (4,021) | ​ | ​ | — | ​ | ​ | (4,021)
Balances at December 31, 2023 | ​ | 33,507 | ​ | $ | 34 | ​ | $ | 40,920 | ​ | $ | 46,485 | ​ | $ | — | ​ | $ | 87,439
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
For the Six Months Ended December 31, 2023 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balances at June 30, 2023 | ​ | 33,248 | ​ | $ | 33 | ​ | $ | 40,098 | ​ | $ | 51,963 | ​ | $ | — | ​ | $ | 92,094
Issuance of restricted common stock | ​ | 288 | ​ | ​ | 1 | ​ | ​ | (1) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Common stock repurchases, including stock surrendered for tax withholding | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (213) | ​ | ​ | (213)
Retirements of treasury stock | ​ | (29) | ​ | ​ | — | ​ | ​ | (213) | ​ | ​ | — | ​ | ​ | 213 | ​ | ​ | —
Stock-based compensation | ​ | — | ​ | ​ | — | ​ | ​ | 1,036 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 1,036
Net income (loss) | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 2,556 | ​ | ​ | — | ​ | ​ | 2,556
Common stock dividends paid | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (8,034) | ​ | ​ | — | ​ | ​ | (8,034)
Balances at December 31, 2023 | ​ | 33,507 | ​ | $ | 34 | ​ | $ | 40,920 | ​ | $ | 46,485 | ​ | $ | — | ​ | $ | 87,439
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
For the Three Months Ended December 31, 2022 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balances at September 30, 2022 | ​ | 33,546 | ​ | $ | 33 | ​ | $ | 42,811 | ​ | $ | 39,533 | ​ | $ | — | ​ | $ | 82,377
Issuance of restricted common stock | ​ | 296 | ​ | ​ | 1 | ​ | ​ | (1) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Forfeitures of restricted stock | ​ | (26) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Common stock repurchases, including stock surrendered for tax withholding | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (61) | ​ | ​ | (61)
Retirements of treasury stock | ​ | (8) | ​ | ​ | — | ​ | ​ | (61) | ​ | ​ | — | ​ | ​ | 61 | ​ | ​ | —
Stock-based compensation | ​ | — | ​ | ​ | — | ​ | ​ | 494 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 494
Net income (loss) | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 10,387 | ​ | ​ | — | ​ | ​ | 10,387
Common stock dividends paid | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (4,059) | ​ | ​ | — | ​ | ​ | (4,059)
Balances at December 31, 2022 | ​ | 33,808 | ​ | $ | 34 | ​ | $ | 43,243 | ​ | $ | 45,861 | ​ | $ | — | ​ | $ | 89,138
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
For the Six Months Ended December 31, 2022 | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balances at June 30, 2022 | ​ | 33,471 | ​ | $ | 33 | ​ | $ | 42,629 | ​ | $ | 32,852 | ​ | $ | — | ​ | $ | 75,514
Issuance of restricted common stock | ​ | 375 | ​ | ​ | 1 | ​ | ​ | (1) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Forfeitures of restricted stock | ​ | (26) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Common stock repurchases, including stock surrendered for tax withholding | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (87) | ​ | ​ | (87)
Retirements of treasury stock | ​ | (12) | ​ | ​ | — | ​ | ​ | (87) | ​ | ​ | — | ​ | ​ | 87 | ​ | ​ | —
Stock-based compensation | ​ | — | ​ | ​ | — | ​ | ​ | 702 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 702
Net income (loss) | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 21,094 | ​ | ​ | — | ​ | ​ | 21,094
Common stock dividends paid | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (8,085) | ​ | ​ | — | ​ | ​ | (8,085)
Balances at December 31, 2022 | ​ | 33,808 | ​ | $ | 34 | ​ | $ | 43,243 | ​ | $ | 45,861 | ​ | $ | — | ​ | $ | 89,138

​

​

See accompanying notes to unaudited condensed consolidated financial statements.

​

​

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Financial Statement Presentation

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

The Company’s oil and natural gas properties consist of non-operated interests in the following areas: the 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 recovery field utilizing water injection wells to pressurize the reservoir; the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana, a CO2 enhanced oil recovery project; the Chaveroo oilfield in Chaves and Roosevelt Counties of New Mexico; as well as small overriding royalty interests in four onshore Texas wells.

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

Principles of Consolidation and Reporting. The unaudited condensed consolidated financial statements include the accounts of Evolution Petroleum Corporation and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The unaudited condensed consolidated financial statements for the previous year may be condensed or include certain reclassifications to conform to the current presentation. To conform with the current year presentation, $0.6 million of accrued ad valorem and production taxes at June 30, 2023 are included with “Accrued taxes other than federal and state income tax” instead of “Accrued payables” as disclosed in Note 12, “Additional Financial Statement Information.” This reclassification has no impact on the previously reported unaudited condensed consolidated balance sheets, net income or stockholders’ equity.

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

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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

producing leasehold, geologic and geophysical costs associated with leasehold or drilling interests, and exploration drilling costs. These costs are excluded until the project is evaluated and proved reserves are established or impairment is determined. The Company entered into a strategic partnership with PEDEVCO Corp. (“PEDEVCO”) on September 12, 2023, to jointly develop the Chaveroo oilfield in the Permian Basin in New Mexico (the “Chaveroo Field”). Per the terms of the participation agreement (the “Participation Agreement”) with PEDEVCO, Evolution paid for acreage associated with nine initial drilling locations totaling approximately $0.4 million. As of December 31, 2023, the Company recorded the payment for the initial acreage as unevaluated costs, excluded from the full cost pool. Refer to Note 3, “Property and Equipment,” for further details.

​

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

Recently Issued Accounting Pronouncements

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

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

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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 six months ended December 31, 2023 and 2022 (in thousands):

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
| ​ | Three Months Ended | ​ | Six Months Ended
​ | ​ | December 31, | ​ | December 31,
|  | 2023 | ​ | 2022 | ​ | 2023 |  | 2022
Revenues | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Crude oil | ​ | $ | 11,759 | ​ | $ | 13,100 | ​ | $ | 24,375 | ​ | $ | 28,263
Natural gas | ​ | ​ | 6,531 | ​ | ​ | 17,370 | ​ | ​ | 12,083 | ​ | ​ | 37,218
Natural gas liquids | ​ | ​ | 2,734 | ​ | ​ | 3,206 | ​ | ​ | 5,167 | ​ | ​ | 7,992
Total revenues | ​ | $ | 21,024 | ​ | $ | 33,676 | ​ | $ | 41,625 | ​ | $ | 73,473

​

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

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

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

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

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

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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. Property and Equipment

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​
​ |  | December 31, 2023 |  | June 30, 2023
Oil and natural gas properties | ​ | ​ |  | ​ | ​ |
Property costs subject to amortization | ​ | $ | 199,526 | ​ | $ | 197,049
Property costs not subject to amortization | ​ | ​ | 3,370 | ​ | ​ | —
Less: Accumulated depletion, depreciation, and impairment | ​ | ​ | (99,415) | ​ | ​ | (91,268)
Oil and natural gas properties, net | ​ | $ | 103,481 | ​ | $ | 105,781

​

As of December 31, 2023, $3.4 million of oil and natural gas property costs were not subject to amortization. On September 12, 2023, the Company entered into a Participation Agreement with PEDEVCO for the joint development of a portion of PEDEVCO’s Permian Basin property in the Chaveroo Field, located in Chaves and Roosevelt Counties, New Mexico. The Participation Agreement does not include any of PEDEVCO’s existing vertical or horizontal wells.

Upon signing the Participation Agreement, the Company paid total cash consideration of $0.4 million, which includes less than $0.1 million of capitalized transactions costs, in exchange for a 50% working interest share in the existing leases associated with two initial development blocks, or nine drilling locations. Following completion of the initial nine development wells, the Company will have the right, but not the obligation, to elect to participate and acquire a 50% working interest share in the next development block, for up to a total of approximately 16,000 gross acres for the payment of $450 per acre. The Company allocated all of the acreage costs associated with the initial acreage purchase to unevaluated oil and natural gas properties. As of December 31, 2023, the Company has incurred approximately $3.0 million in capital expenditures related to the drilling and completion of an initial three wells. These capital expenditures are recorded as unevaluated property costs.

The Company uses the full cost method of accounting for its investments in oil and natural gas properties. All costs of acquisition, exploration, and development of oil and natural gas reserves are capitalized as the cost of oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs would be charged to expense as a write-down of oil and natural gas properties.

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

Depletion of oil and natural gas properties was $8.1 million and $6.5 million for the six months ended December 31, 2023 and 2022, respectively. During the six months ended December 31, 2023 and 2022, the Company incurred development capital expenditures of $2.4 million and $2.1 million, respectively.

At December 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 December 31, 2023 of the West Texas Intermediate (“WTI”) crude oil spot price

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

of $78.21 per barrel and Henry Hub natural gas spot price of $2.63 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $31.57, which was based on historical differentials to WTI as NGLs do not have any single comparable reference index price. Using these prices, at December 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 December 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 December 31, 2022 of the WTI crude oil spot price of $94.14 per barrel and Henry Hub natural gas spot price of $6.40 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $48.50, which was based on historical prices received as NGLs do not have any single comparable reference index price. Using these prices, at December 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.

Note 4. Senior Secured Credit Facility

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

​

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 December 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. As of December 31, 2023, the Company is 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

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

Note 5. 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, 2020 through June 30, 2023 for federal tax purposes and for the fiscal years ended June 30, 2019 through June 30, 2023 for state tax purposes. To the extent the Company utilizes net operating losses (“NOLs”) generated in earlier years, such earlier years may also be subject to audit.

For six months ended December 31, 2023, the Company recognized income tax expense of $1.0 million and had an effective tax rate of 28.5% compared to income tax expense of $6.0 million and an effective tax rate of 22.1% for the six months ended December 31, 2022.

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, 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 6. Derivatives

The Company is exposed to certain risks relating to its ongoing business operations, including commodity price risk and interest rate risk. In accordance with the Company’s strategy and the requirements under the Senior Secured Credit Facility (as discussed in Note 4, “Senior Secured Credit Facility”), it may hedge or may be required to hedge a varying portion of anticipated oil and natural gas production for future periods. Derivatives are carried at fair value on the unaudited condensed consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the unaudited condensed consolidated statements of operations for the period in which the change occurs. The Company’s hedge strategies and objectives may change significantly as its operational profile changes or as required under the Senior Secured Credit Facility. The Company does not enter into derivative contracts for speculative trading purposes.

It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of June 30, 2023, all of the Company’s derivative contracts had expired. The Company has no open derivative contracts as of December 31, 2023 or June 30, 2023, and the Company did not post collateral under any of its derivative contracts during the periods in which contracts were open as they were secured under the Company’s Senior Secured Credit Facility.

The Company has in the past, and may utilize in the future, commodity derivative contracts such as costless put/call collars and fixed-price swaps to hedge a portion of its anticipated future production. A costless collar consists of a sold

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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”). 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 six months ended December 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 | ​ | Six Months Ended
as hedging contracts | ​ | recognized in income on | ​ | December 31, | ​ | December 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 | ​ | $ | — | ​ | $ | (224) | ​ | $ | — | ​ | $ | (1,946)
Unrealized gain (loss) on derivative contracts | ​ | Other income and expenses - net gain (loss) on derivative contracts | ​ | ​ | — | ​ | ​ | 1,070 | ​ | ​ | — | ​ | ​ | 2,189
Total net gain (loss) on derivative contracts | ​ | ​ | ​ | $ | — | ​ | $ | 846 | ​ | $ | — | ​ | $ | 243

​

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 7. 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.

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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.

​

As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgement, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any period presented in this report. The Company did not have any open positions at December 31, 2023 or June 30, 2023.

​

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 8, “Asset Retirement Obligations,” for a reconciliation of the beginning and ending balances of the liability for the Company’s ARO.

Note 8. Asset Retirement Obligations

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

​

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The following is a reconciliation of the activity related to the Company’s ARO liability (inclusive of the current portion) for the period ended December 31, 2023 (in thousands):

​ | ​ | ​ | ​
|  | December 31, 2023
Asset retirement obligations — beginning of period | ​ | $ | 17,067
Accretion of discount | ​ | ​ | 712
Asset retirement obligations — end of period | ​ | ​ | 17,779
Less: current asset retirement obligations | ​ | ​ | (41)
Long-term portion of asset retirement obligations | ​ | $ | 17,738

​

​

Note 9. Commitments and Contingencies

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

Note 10. Stockholders’ Equity

Common Stock

As of December 31, 2023, the Company had 33,506,794 shares of common stock outstanding.

The Company began paying quarterly cash dividends on common stock in December 2013. As of December 31, 2023, the Company has cumulatively paid over $110.4 million in cash dividends. The Company paid dividends of $8.0 million and $8.1 million to its common stockholders during the six months ended December 31, 2023 and 2022, respectively. The following table reflects the dividends paid per share within the respective three-month periods:

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Fiscal Year
​ |  | 2024 |  | 2023
Second quarter ended December 31, | ​ | $ | 0.120 | ​ | $ | 0.120
First quarter ended September 30, | ​ | ​ | 0.120 | ​ | ​ | 0.120

​

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

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In November 2023, the Company entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan is effective until June 30, 2024, unless extended, renewed or terminated by the Company, and has a maximum authorized amount of $0.8 million over that period. The Company may alter the terms of the plan from time to time to the extent it determines changes are necessary to achieve the intended objectives of the repurchase program. No shares were purchased under this plan during the period ended December 31, 2023.

​

During the six months ended December 31, 2023 and 2022, the Company acquired treasury stock upon the ordinary course of scheduled vestings of employee stock-based awards to fund payroll tax withholding obligations. These treasury shares were subsequently cancelled. Such shares were valued at fair market value on the date of vesting.

​

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Six Months Ended
​ | ​ | December 31,
​ |  | 2023 | ​ | 2022
Number of treasury shares acquired | ​ | ​ | 29,236 | ​ | ​ | 12,049
Average cost per share | ​ | $ | 7.29 | ​ | $ | 7.19
Total cost of treasury shares acquired | ​ | $ | 213,015 | ​ | $ | 86,690

​

Expected Tax Treatment of Dividends

For the fiscal year ended June 30, 2023, all common stock dividends for that fiscal year were treated for tax purposes as qualified dividend income to the recipients. Based on its current projections for the fiscal year ended June 30, 2024, the Company expects all common stock dividends for such period to be treated as qualified dividend income to the recipients. Such projections are based on the Company’s reasonable expectations as of December 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 December 31, 2023 and June 30, 2023, approximately 0.9 million shares and 1.3 million shares, respectively, remained available for grant under the 2016 Plan.

The Company estimates the fair value of stock-based compensation awards on the grant date to provide the basis for future compensation expense. During the three and six months ended December 31, 2023, the Company recognized $0.6 million and $1.0 million, respectively, related to stock-based compensation. During the three and six months ended December 31, 2022, the Company recognized $0.5 million and $0.7 million, respectively, related to stock-based compensation expense. Stock-based compensation expense is recorded as a component of “General and administrative expenses” on the unaudited condensed consolidated statements of operations.

Time-Vested Restricted Stock Awards

Time-vested restricted stock awards contain service-based vesting conditions and expire after a maximum of four years from the date of grant if unvested. The common shares underlying these awards are issued on the date of grant and participate in dividends paid by the Company. These service-based awards vest with continuous employment by the Company, generally in annual installments over terms of three to four years. Awards to the Company’s directors

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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 six months ended December 31, 2023, the Company granted a total of 0.4 million equity awards that included 0.2 million time-vested restricted stock awards, 0.1 million performance-based restricted stock awards, and 0.1 million performance-based contingent stock units.

During the six months ended December 31, 2022, the Company granted a total of 0.4 million equity awards that included 0.3 million time-vested restricted stock awards, 0.1 million performance-based restricted stock awards, and less than 0.05 million of performance-based contingent stock units.

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

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Six Months Ended
​ | ​ | December 31,
​ |  | 2023 |  | 2022
Weighted average fair value of performance-based awards granted | ​ | $ | 3.58 | ​ | $ | 6.69
Risk-free interest rate | ​ | ​ | 4.87% | ​ | ​ | 3.91% to 4.44%
Expected term in years | ​ | ​ | 2.77 | ​ | ​ | 2.66 to 2.78
Expected volatility | ​ | ​ | 55.0% | ​ | ​ | 69.6% to 70.9%
Dividend yield | ​ | ​ | 7.4% | ​ | ​ | 6.1%

​

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

​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | Weighted
​ | ​ | Number of | ​ | Average
​ | ​ | Restricted | ​ | Grant-Date
Award Type |  | Shares |  | Fair Value
Time-vested awards | ​ | 439,603 | ​ | $ | 6.61
Performance-based awards | ​ | 278,688 | ​ | ​ | 5.46
Unvested at December 31, 2023 | ​ | 718,291 | ​ | $ | 6.16

​

​

The following table sets forth the restricted stock award transactions for the six months ended December 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, 2023 | ​ | 595,414 | ​ | ​ | 6.48 | ​ | $ | 2,827 | ​ | 2.4
Time-vested shares granted | ​ | 152,192 | ​ | ​ | 6.24 | ​ | ​ | ​ | ​ | ​
Performance-based shares granted | ​ | 136,315 | ​ | ​ | 4.80 | ​ | ​ | ​ | ​ | ​
Vested | ​ | (165,630) | ​ | ​ | 6.26 | ​ | ​ | ​ | ​ | ​
Unvested at December 31, 2023 | ​ | 718,291 | ​ | $ | 6.16 | ​ | $ | 3,470 | ​ | 2.1

​

​

The following table sets forth contingent restricted stock unit transactions for the six months ended December 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, 2023 | ​ | 96,398 | ​ | $ | 3.49 | ​ | $ | 195 | ​ | 1.9
Performance-based awards granted | ​ | 102,239 | ​ | ​ | 1.95 | ​ | ​ | ​ | ​ | ​
Unvested at December 31, 2023 | ​ | 198,637 | ​ | $ | 2.70 | ​ | $ | 320 | ​ | 2.0

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Note 11. 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 | ​ | Six Months Ended
​ | ​ | December 31, | ​ | December 31,
|  | 2023 | ​ | 2022 | ​ | 2023 |  | 2022
Numerator | ​ | ​ |  | ​ | ​ |  | ​ | ​ |  | ​ | ​ |
Net income (loss) | ​ | $ | 1,082 | ​ | $ | 10,387 | ​ | $ | 2,556 | ​ | $ | 21,094
Undistributed earnings allocated to unvested restricted stock | ​ | ​ | (24) | ​ | ​ | (162) | ​ | ​ | (51) | ​ | ​ | (274)
Net income (loss) for earnings per share calculation | ​ | $ | 1,058 | ​ | $ | 10,225 | ​ | $ | 2,505 | ​ | $ | 20,820
​ | ​ | ​ |  | ​ | ​ |  | ​ | ​ |  | ​ | ​ |
Denominator | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Weighted average number of common shares outstanding — Basic | ​ | ​ | 32,693 | ​ | ​ | 33,174 | ​ | ​ | 32,676 | ​ | ​ | 33,154
Effect of dilutive securities: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Unvested restricted stock awards | ​ | ​ | 171 | ​ | ​ | 206 | ​ | ​ | 225 | ​ | ​ | 195
Unvested contingent restricted stock units | ​ | ​ | 36 | ​ | ​ | 14 | ​ | ​ | 39 | ​ | ​ | 7
Weighted average number of common shares and dilutive potential common shares used in diluted earnings per share | ​ | ​ | 32,900 | ​ | ​ | 33,394 | ​ | ​ | 32,940 | ​ | ​ | 33,356
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) per common share — Basic | ​ | $ | 0.03 | ​ | $ | 0.31 | ​ | $ | 0.08 | ​ | $ | 0.63
Net income (loss) per common share — Diluted | ​ | $ | 0.03 | ​ | $ | 0.31 | ​ | $ | 0.08 | ​ | $ | 0.62

​

Unvested restricted stock awards (both time-vested and performance-based), totaling approximately 0.2 million and 0.1 million for the three and six months ended December 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 (both time-vested and performance-based), totaling approximately 90,000 and 49,000 for the three and six months ended December 31, 2022, respectively, were not included in the computation of diluted earnings per common share because the effect would have been anti-dilutive.

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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

​

Note 12. Additional Financial Statement Information

​

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

​ | ​ | ​ | ​ | ​ | ​ | ​
|  | December 31, 2023 |  | June 30, 2023
Prepaid expenses and other current assets: | ​ | ​ | ​ | ​ | ​ | ​
Other receivables | ​ | $ | 21 | ​ | $ | 18
Prepaid insurance | ​ | ​ | 468 | ​ | ​ | 727
Prepaid federal and state income taxes | ​ | ​ | 1,371 | ​ | ​ | 805
Carryback of EOR tax credit | ​ | ​ | 347 | ​ | ​ | 347
Prepaid other | ​ | ​ | 362 | ​ | ​ | 380
Total prepaid expenses and other current assets | ​ | $ | 2,569 | ​ | $ | 2,277
​ | ​ | ​ | ​ | ​ | ​ | ​
Other assets: | ​ | ​ | ​ | ​ | ​ | ​
Deposit | ​ | $ | 1,158 | ​ | $ | 1,158
Right of use asset under operating lease | ​ | ​ | 179 | ​ | ​ | 183
Total other assets | ​ | $ | 1,337 | ​ | $ | 1,341
​ | ​ | ​ | ​ | ​ | ​ | ​
Accrued liabilities and other: | ​ | ​ | ​ | ​ | ​ | ​
Accrued payables | ​ | $ | 2,890 | ​ | $ | 3,005
Accrued capital expenditures | ​ | ​ | 593 | ​ | ​ | 167
Accrued incentive and other compensation | ​ | ​ | 611 | ​ | ​ | 941
Accrued royalties payable | ​ | ​ | 1,046 | ​ | ​ | 977
Accrued taxes other than federal and state income tax | ​ | ​ | 980 | ​ | ​ | 739
Accrued severance | ​ | ​ | — | ​ | ​ | 81
Operating lease liability | ​ | ​ | 97 | ​ | ​ | 59
Asset retirement obligations due within one year | ​ | ​ | 41 | ​ | ​ | 55
Accrued - other | ​ | ​ | 36 | ​ | ​ | 3
Total accrued liabilities and other | ​ | $ | 6,294 | ​ | $ | 6,027

​

​

​

​

Note 13. Subsequent Events

Dividend Declaration

​

On February 5, 2024, the Company declared a quarterly cash dividend of $0.120 per share of common stock to shareholders of record on March 15, 2024 and payable on March 28, 2024.

​

Derivatives

​

On January 30, 2024, the Company entered into new derivative contracts covering 40,775 barrels of its crude oil comprised of put positions at $75.00 per barrel and fixed-price swap positions at $73.41 per barrel over the effective period of February 2024 through June 2024.

​

SCOOP/STACK Acquisitions

​

On January 5, 2024, the Company entered into separate Purchase and Sale Agreements (“PSAs”) with Red Sky Resources III, LLC, Red Sky Resources IV, LLC, and Coriolis Energy Partners I, LLC. Pursuant to the PSAs, the Company will acquire non-operating working interests in oil and natural gas properties in the SCOOP and STACK plays in central Oklahoma for a combined purchase price of approximately $43.5 million in cash. Contemporaneous with the execution of the PSAs, the Company paid deposits totaling $3.26 million. The Company expects to fund the balance of the consideration to be paid in the transactions with a combination of cash on hand and borrowings under its senior secured credit facility.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The acquired assets consist of an average working interest of approximately 3% net to Evolution, in 231 producing wells and as of the effective date, 21 gross drilled and uncompleted wells to be funded through completion by the sellers, in the SCOOP and STACK plays of the Anadarko Basin in Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, and Stephens counties, Oklahoma.

​

The effective date of these acquisitions is November 1, 2023 and each transaction is expected to close in mid-February during the third quarter of fiscal 2024. The PSAs governing each transaction contain customary representations and warranties, covenants, indemnification, closing conditions and termination provisions and also provide for various purchase price adjustments, including adjusting the purchase price for the net cash flows of the properties between the effective date and closing date of the acquisition, to be calculated as of the closing date.

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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 December 31, 2023, our first quarter of fiscal year 2024.

“Year-ago quarter” refers to the three months ended December 31, 2022, our first quarter of fiscal year 2023.

Executive Overview

General

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

Our oil and natural gas properties consist of non-operated interests in the following areas: the 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; the Chaveroo oilfield in Chaves and Roosevelt Counties of New Mexico; as well as small overriding royalty interests in four onshore central Texas wells.

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

Our non-operated interests in the Williston Basin, an oil and natural gas producing property, consist of approximately 39% average net working interest and approximately 33% average net revenue interest located on approximately 43,300 net acres (approximately 92% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota. The properties are operated by Foundation Energy Management, an established operator in the geographic region.

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

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

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remaining working interest in the Hamilton Dome Field. The Hamilton Dome Field is located in the southwest region of the Big Horn Basin in northwest Wyoming.

Our non-operated interests in the Delhi Field, a CO2-EOR project producing oil and NGLs, consist of approximately 24% average net working interest, with an associated 19% revenue interest and separate overriding royalty and mineral interests of approximately 7% yielding a total average net revenue interest of approximately 26%. The field is operated by Denbury Onshore LLC (“Denbury”). 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.

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

Recent Developments

SCOOP/STACK Acquisitions

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On January 5, 2024, we entered into separate Purchase and Sale Agreements (“PSAs”) with Red Sky Resources III, LLC, Red Sky Resources IV, LLC, and Coriolis Energy Partners I, LLC. Pursuant to the PSAs, we will acquire non-operating working interests in oil and natural gas properties in the SCOOP and STACK plays in central Oklahoma for a combined purchase price of approximately $43.5 million in cash (“the SCOOP/STACK Acquisitions”). Contemporaneous with the execution of the PSAs, we paid deposits totaling $3.26 million. We expect to fund the balance of the consideration to be paid in the transactions with a combination of cash on hand and borrowings under our senior secured credit facility.

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The acquired assets consist of an average working interest of approximately 3% net to us, in 231 producing wells and as of the effective date, 21 gross drilled and uncompleted wells to be funded through completion by the sellers, in the SCOOP and STACK plays of the Anadarko Basin in Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, and Stephens counties, Oklahoma. The acquisitions also include approximately 3,700 net acres with more than 300 associated potential drilling opportunities.

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The effective date of these acquisitions is November 1, 2023 and each transaction is expected to close in mid-February during the third quarter of fiscal 2024. The PSAs governing each transaction contain customary representations and warranties, covenants, indemnification, closing conditions and termination provisions and also provide for various purchase price adjustments, including adjusting the purchase price for the net cash flows of the properties between the effective date and closing date of the acquisition, to be calculated as of the closing date.

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Appointment of Chief Accounting Officer

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

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Share Repurchase Program

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In November 2023, we entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan is effective until June 30, 2024, unless extended, renewed or terminated, and has a maximum authorized amount of $0.8 million over that period. We may alter the terms of the plan from time to time to the extent we determine changes are necessary to achieve the intended objectives of our repurchase program. No shares were repurchased under this program during the period ended December 31, 2023.

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Chaveroo Oilfield Participation Agreement

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

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

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

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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.

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

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

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

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

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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 December 31, 2023 and June 30, 2023, we had no borrowings outstanding on our Senior Secured Credit Facility. As of December 31, 2023, we had $8.5 million in cash and cash equivalents compared to $11.0 million in cash and cash equivalents at June 30, 2023. Our primary sources of liquidity and capital resources during the six months ended December 31, 2023 were cash provided by operations and the unused portion of our Senior Secured Credit Facility. Our primary uses of liquidity and capital resources for the three months ended December 31, 2023 were cash dividend payments to our common stockholders, capital expenditures on our existing oil and natural gas properties, and initial cash consideration paid for unevaluated oil and natural gas properties under our Participation Agreement with PEDEVCO. As of December 31, 2023, working capital was $6.6 million, a decrease of $2.3 million from working capital of $8.9 million as of June 30, 2023.

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

Borrowings bear interest, at our option, at either the SOFR plus 2.80% or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%. During the six months ended December 31, 2023, we did not have any borrowings outstanding under our Senior Secured Credit Facility. 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 December 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, extended the maturity of our Senior Secured Credit Facility to April 9, 2026, converted our benchmark interest rate from LIBOR to SOFR plus a credit spread adjustment of 0.05%, and modified the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, to $95.0 million. We are required to enter into hedges on a rolling 12-month basis when the borrowings under the Senior Secured Credit Facility exceed 25% of the Margined Collateral Value. The required amount of hedged oil and natural gas production is related to the amount of borrowings outstanding. At each redetermination, our Margined Collateral Value takes into account the estimated value of our oil and natural gas properties, proved developed reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. We expect to be subject to these hedge requirements upon the closing of our pending SCOOP/STACK Acquisitions.

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

We are pursuing new growth opportunities through acquisitions and other transactions. In addition to cash on hand, we have access to the undrawn portion of the borrowing base available under our Senior Secured Credit Facility, totaling $50.0 million as of December 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 41 consecutive quarterly dividends. Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of our financial strategy, and it is our long-term goal to increase dividends over time, as appropriate. On February 5, 2024, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on March 15, 2024 and payable on March 28, 2024.

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

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In November 2023, we entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan is effective until June 30, 2024, unless extended, renewed or terminated, and has a maximum authorized amount of $0.8 million over that period. We may alter the terms of the plan from time to time to the extent we determine changes are necessary to achieve the intended objectives of our repurchase program.

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Capital Expenditures

During the six months ended December 31, 2023, we incurred $5.7 million in capital expenditures. During the current quarter, we participated in the drilling and completion of the initial three wells in the Chaveroo Field. During the first fiscal quarter, we participated in the drilling and completion of two new wells in the Delhi Field. First production at Chaveroo Field is expected in February 2024. Production of the Delhi wells came online in the first fiscal quarter of 2024 and produced consistently in the second fiscal quarter.

Based on discussions with our operators, we expect capital workover projects to continue in all the fields. Overall, for fiscal year 2024, we expect budgeted capital expenditures to be in the range of $10.0 million to $14.0 million, which excludes any potential acquisitions. Our expected capital expenditures for fiscal year 2024 include the two new drilled wells at Delhi Field and three wells at Chaveroo Field, both of which are discussed above. We also expect to start incurring capital expenditures, in the fourth quarter at Chaveroo Field, for the second development block consisting of six horizontal wells. As mentioned in Recent Developments, the Company has entered into three separate definitive agreements to purchase oil and natural gas properties in the SCOOP/STACK plays in central Oklahoma for a combined purchase price of $43.5 million, before customary closing adjustments. Our budgeted capital expenditures discussed above do not include any potential capital projects associated with properties in the SCOOP/STACK Acquisitions.

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

Full Cost Pool Ceiling Test

Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated depletion, depreciation, and amortization and related deferred taxes, are limited to the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and natural gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average first day of the month price for our petroleum products during the 12-month period ending with the balance sheet date. The prices used in calculating our ceiling test as of December 31, 2023 were $78.21 per barrel of oil, $2.63 per MMBtu of natural gas and $31.57 per barrel of NGLs. As of December 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 December 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. Additionally, a 10% reduction in respective commodity prices at December 31, 2023, while all other factors remained constant, would not have generated an impairment.

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Overview of Cash Flow Activities

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Six Months Ended December 31, | ​ | ​ | ​
​ |  | 2023 |  | 2022 |  | Change
Cash flows provided by operating activities | ​ | $ | 11,378 | ​ | $ | 27,769 | ​ | $ | (16,391)
Cash flows used in investing activities | ​ | ​ | (5,705) | ​ | ​ | (2,917) | ​ | ​ | (2,788)
Cash flows used in financing activities | ​ | ​ | (8,247) | ​ | ​ | (29,422) | ​ | ​ | 21,175
Net increase in cash and cash equivalents | ​ | $ | (2,574) | ​ | $ | (4,570) | ​ | $ | 1,996

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Cash provided by operating activities for the six months ended December 31, 2023 decreased $16.4 million compared to the six months ended December 31, 2022 primarily due to a decrease in revenues. Total revenues decreased $31.8 million as compared to the prior year period primarily due to lower commodity prices coupled with lower sales volumes. Our average realized price per barrel of oil equivalent (“BOE”) decreased $18.37, or 34.1% from the prior year period. Refer to “Results of Operations” below for further information.

Cash used in investing activities for the six months ended December 31, 2023 increased $2.8 million compared to the six months ended December 31, 2022 due to an increase in capital expenditures related to the drilling and completion of three new wells in the Chaveroo Field during the current quarter.

Net cash flows used in financing activities for the six months ended December 31, 2023 decreased $21.2 million from the six months ended December 31, 2022. In the prior year period, we had repayments totaling $21.3 million of borrowings outstanding under our Senior Secured Credit Facility. For the six months ended December 31, 2023 and 2022, cash dividends paid to our common stockholders were $8.0 million and $8.1 million, respectively.

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Results of Operations

Three Months Ended December 31, 2023 and 2022

We reported net income of $1.1 million and $10.4 million for the three months ended December 31, 2023 and 2022, respectively. The following table summarizes the comparison of financial information for the periods presented:

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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
| ​ | Three Months Ended | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, | ​ | ​ | ​ | ​ | ​ | ​
(in thousands, except per unit and per BOE amounts) |  | 2023 | ​ | 2022 |  | Variance |  | Variance %
Net income (loss) | ​ | $ | 1,082 | ​ | $ | 10,387 | ​ | $ | (9,305) | ​ | (89.6) | %
Revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Crude oil | ​ | ​ | 11,759 | ​ | ​ | 13,100 | ​ | ​ | (1,341) | ​ | (10.2) | %
Natural gas | ​ | ​ | 6,531 | ​ | ​ | 17,370 | ​ | ​ | (10,839) | ​ | (62.4) | %
Natural gas liquids | ​ | ​ | 2,734 | ​ | ​ | 3,206 | ​ | ​ | (472) | ​ | (14.7) | %
Total revenues | ​ | ​ | 21,024 | ​ | ​ | 33,676 | ​ | ​ | (12,652) | ​ | (37.6) | %
Operating costs: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating costs: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
CO2 costs | ​ | ​ | 1,628 | ​ | ​ | 2,007 | ​ | ​ | (379) | ​ | (18.9) | %
Ad valorem and production taxes | ​ | ​ | 1,272 | ​ | ​ | 2,096 | ​ | ​ | (824) | ​ | (39.3) | %
Other lease operating costs | ​ | ​ | 9,458 | ​ | ​ | 10,938 | ​ | ​ | (1,480) | ​ | (13.5) | %
Depletion, depreciation, and accretion: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Depletion of full cost proved oil and natural gas properties | ​ | ​ | 4,238 | ​ | ​ | 3,178 | ​ | ​ | 1,060 | ​ | 33.4 | %
Accretion of asset retirement obligations | ​ | ​ | 360 | ​ | ​ | 280 | ​ | ​ | 80 | ​ | 28.6 | %
General and administrative expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
General and administrative | ​ | ​ | 1,938 | ​ | ​ | 2,087 | ​ | ​ | (149) | ​ | (7.1) | %
Stock-based compensation | ​ | ​ | 564 | ​ | ​ | 494 | ​ | ​ | 70 | ​ | 14.2 | %
Other income (expense): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net gain (loss) on derivative contracts | ​ | ​ | — | ​ | ​ | 846 | ​ | ​ | (846) | ​ | (100.0) | %
Interest and other income | ​ | ​ | 104 | ​ | ​ | 7 | ​ | ​ | 97 | ​ | 1,385.7 | %
Interest expense | ​ | ​ | (34) | ​ | ​ | (129) | ​ | ​ | 95 | ​ | (73.6) | %
Income tax (expense) benefit | ​ | ​ | (554) | ​ | ​ | (2,933) | ​ | ​ | 2,379 | ​ | (81.1) | %
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Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Crude oil (MBBL) | ​ | ​ | 159 | ​ | ​ | 166 | ​ | ​ | (7) | ​ | (4.2) | %
Natural gas (MMCF) | ​ | ​ | 1,951 | ​ | ​ | 2,367 | ​ | ​ | (416) | ​ | (17.6) | %
Natural gas liquids (MBBL) | ​ | ​ | 96 | ​ | ​ | 106 | ​ | ​ | (10) | ​ | (9.4) | %
Equivalent (MBOE)(1) | ​ | ​ | 580 | ​ | ​ | 667 | ​ | ​ | (87) | ​ | (13.0) | %
Average daily production (BOEPD)(1) | ​ | ​ | 6,304 | ​ | ​ | 7,250 | ​ | ​ | (946) | ​ | (13.0) | %
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Average price per unit(2): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Crude oil (BBL) | ​ | $ | 73.96 | ​ | $ | 78.92 | ​ | $ | (4.96) | ​ | (6.3) | %
Natural gas (MCF) | ​ | ​ | 3.35 | ​ | ​ | 7.34 | ​ | ​ | (3.99) | ​ | (54.4) | %
Natural Gas Liquids (BBL) | ​ | ​ | 28.48 | ​ | ​ | 30.25 | ​ | ​ | (1.77) | ​ | (5.9) | %
Equivalent (BOE)(1) | ​ | ​ | 36.25 | ​ | ​ | 50.49 | ​ | ​ | (14.24) | ​ | (28.2) | %
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average cost per unit: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating costs: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating costs: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
CO2 costs | ​ | $ | 2.81 | ​ | $ | 3.01 | ​ | ​ | (0.20) | ​ | (6.6) | %
Ad valorem and production taxes | ​ | ​ | 2.19 | ​ | ​ | 3.14 | ​ | ​ | (0.95) | ​ | (30.3) | %
Other lease operating costs | ​ | ​ | 16.31 | ​ | ​ | 16.40 | ​ | ​ | (0.09) | ​ | (0.5) | %
Depletion of full cost proved oil and natural gas properties | ​ | ​ | 7.31 | ​ | ​ | 4.76 | ​ | ​ | 2.55 | ​ | 53.6 | %
General and administrative expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
General and administrative | ​ | ​ | 3.34 | ​ | ​ | 3.13 | ​ | ​ | 0.21 | ​ | 6.7 | %
Stock-based compensation | ​ | ​ | 0.97 | ​ | ​ | 0.74 | ​ | ​ | 0.23 | ​ | 31.1 | %

(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 $21.0 million and $33.7 million for the three months ended December 31, 2023 and 2022, respectively. The decrease in revenues is primarily due to the decrease in our average realized price per BOE coupled with a decrease in our sales volumes. Our average realized commodity price (excluding the impact of derivative contracts) for the three months ended December 31, 2023 decreased approximately $14.24 per BOE, or 28.2%, compared to the prior year period. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, inventory storage levels, basis differentials and other factors. Realized natural gas prices decreased 54.4% from the prior year period, driving the largest decrease in revenues. This was partially attributed to the prior year period benefit of strong natural gas price differentials received at the Jonah Field where we realized an average natural gas price of $11.00 per MCF in the prior year period compared to $4.87 in the current year quarter. Average daily equivalent production decreased 13.0% from 7,250 BOEPD in the prior year period to 6,304 BOEPD in the current period. We began experiencing production declines and downtime in April 2023 at Barnett Shale. Production declines were primarily related to compression issues due to excessive heat, downtime in the gathering and processing system, pipeline rerouting and optimization, and our operator’s decision to temporarily shut-in certain low margin wells. As of December 31, 2023, the midstream issues have been moderated, but due to low natural gas prices the shut-in wells remain offline which has continued to impact production volumes.

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Lease Operating Costs

Ad valorem and production taxes were $1.3 million and $2.1 million for the three months ended December 31, 2023 and 2022, respectively. On a per unit basis, ad valorem and production taxes were $2.19 per BOE and $3.14 per BOE for the three months ended December 31, 2023 and 2022, respectively. The decrease in ad valorem and production taxes is primarily due to decreases in oil and natural gas prices as well as decreased production volumes described above as production taxes are based on sales at the wellhead.

The following table summarizes CO2 costs per Mcf and CO2 volumes for the three months ended December 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.

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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
| ​ | Three Months Ended | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, | ​ | ​ | ​ | ​ | ​ | ​
​ |  | 2023 |  | 2022 |  | Variance |  | Variance %
CO2 costs per MCF | ​ | $ | 0.97 | ​ | $ | 1.01 | ​ | $ | (0.04) | ​ | (4.0) | %
CO2 volumes (MMCF per day, gross) | ​ | ​ | 76.4 | ​ | ​ | 90.7 | ​ | ​ | (14.3) | ​ | (15.8) | %

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The $0.4 million decrease in CO2 costs for the three months ended December 31, 2023 was primarily due to a 15.8% decrease in purchased CO2 volumes combined with a 4.0% decrease in CO2 costs per MCF, which was driven by a decrease in our average realized oil price. CO2 volumes injected were reduced compared to prior year period due to a reduction in CO2 purchase nominations. In the prior year period, CO2 purchase nominations were higher to compensate for reduced reservoir pressure. CO2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. We do not have any ownership in the CO2 pipeline which is owned and operated by Denbury. On a per unit basis, CO2 costs were $2.81 per BOE and $3.01 per BOE for the three months ended December 31, 2023 and 2022, respectively.

Other lease operating costs decreased $1.5 million, or 13.5%, compared to the prior year period primarily due to lower production combined with the lower commodity price environment. On a per unit basis, other lease operating costs decreased to $16.31 per BOE for the three months ended December 31, 2023 from $16.40 per BOE in the year-ago quarter. The largest decrease in operating costs is at our Barnett Shale properties and the Delhi Field. At the Barnett Shale, significant cost savings efforts are being prioritized due to the lower realized natural gas prices and the shut-in of certain low margin wells at current natural gas prices. We are incurring lower operating costs in all cost categories, especially lower water hauling costs and lower gathering, transportation and processing charges. At Delhi Field, we have seen lower electricity charges due to lower commodity prices.

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Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased $1.1 million or 33.4% from $3.2 million to $4.2 million for the three months ended December 31, 2023 primarily due to an increase in the depletion rate. On a per unit basis, depletion expense was $7.31 per BOE and $4.76 per BOE for the three months ended December 31, 2023 and 2022, respectively. The depletion rate of our unit of production calculation increased due to decreases in proved reserve volumes as well as increases in our depletable base due to capital expenditures since December 31, 2022. Our proved reserves volumes have decreased since the prior year period primarily due to oil and natural gas volumes produced combined with a reduction in the SEC prices used in calculating proved reserves since the prior year period.

General and Administrative Expenses

General and administrative expenses for the three months ended December 31, 2023 decreased $0.1 million, or 7.1%, to $1.9 million compared to $2.1 million for the prior year period. The decrease primarily relates to lower consulting fees totaling approximately $0.1 million related to our search for a CEO in the prior year period. On a per unit basis, general and administrative expenses were $3.34 per BOE and $3.13 per BOE for the three months ended December 31, 2023 and 2022, respectively. The slight increase on a per unit basis is primarily the result of the decrease in production for the current year period.

Stock-based Compensation Expense

Stock-based compensation expense for the three months ended December 31, 2023 increased $0.1 million to $0.6 million compared to $0.5 million in the prior year due to new awards granted during the current year.

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 of December 31, 2023, we did not have any open crude oil or natural gas derivative contracts. In the prior year period, because 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 those hedges resulted in realized losses on derivative contracts for the prior year period.

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, | ​ | ​ | ​ | ​ | ​ | ​
(in thousands, except per unit and per BOE amounts) |  | 2023 |  | 2022 |  | Variance |  | Variance %
Realized gain (loss) on derivative contracts | ​ | $ | — | ​ | $ | (224) | ​ | $ | 224 | ​ | (100.0) | %
Unrealized gain (loss) on derivative contracts | ​ | ​ | — | ​ | ​ | 1,070 | ​ | ​ | (1,070) | ​ | (100.0) | %
Total net gain (loss) on derivative contracts | ​ | $ | — | ​ | $ | 846 | ​ | $ | (846) | ​ | (100.0) | %
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average realized crude oil price per BBL | ​ | $ | 73.96 | ​ | $ | 78.92 | ​ | $ | (4.96) | ​ | (6.3) | %
Cash effect of oil derivative contracts per BBL | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | — | %
Crude oil price per BBL (including impact of realized derivatives) | ​ | $ | 73.96 | ​ | $ | 78.92 | ​ | $ | (4.96) | ​ | (6.3) | %
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average realized natural gas price per MCF | ​ | $ | 3.35 | ​ | $ | 7.34 | ​ | $ | (3.99) | ​ | (54.4) | %
Cash effect of natural gas derivative contracts per MCF | ​ | ​ | — | ​ | ​ | (0.09) | ​ | ​ | 0.09 | ​ | (100) | %
Natural gas price per MCF (including impact of realized derivatives) | ​ | $ | 3.35 | ​ | $ | 7.25 | ​ | $ | (3.90) | ​ | (53.8) | %

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Interest Expense

Interest expense decreased $0.1 million for the three months ended December 31, 2023 compared to the prior year period primarily due to repayments of borrowings outstanding on our Senior Secured Credit Facility during the prior fiscal year.

Income Tax (Expense) Benefit

For the three months ended December 31, 2023, we recognized income tax expense of $0.6 million on net income before income taxes of $1.6 million compared to income tax expense of $2.9 million on net income before income taxes of $13.3 million for the three months ended December 31, 2022. The effective tax rates were 33.9% and 22.0% for three months ended December 31, 2023 and 2022, respectively. The effective tax rate increased compared to the prior year period as projected state income taxes have become a larger component of our overall income tax expense during the period.

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Six Months Ended December 31, 2023 and 2022

We reported net income of $2.6 million and $21.1 million for the six months ended December 31, 2023 and 2022, respectively. The following table summarizes the comparison of financial information for the periods presented:

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
| ​ | Six Months Ended | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, | ​ | ​ | ​ | ​ | ​ | ​
(in thousands, except per unit and per BOE amounts) |  | 2023 |  | 2022 |  | Variance |  | Variance %
Net income (loss) | ​ | $ | 2,556 | ​ | $ | 21,094 | ​ | $ | (18,538) | ​ | (87.9) | %
Revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Crude oil | ​ | ​ | 24,375 | ​ | ​ | 28,263 | ​ | ​ | (3,888) | ​ | (13.8) | %
Natural gas | ​ | ​ | 12,083 | ​ | ​ | 37,218 | ​ | ​ | (25,135) | ​ | (67.5) | %
Natural gas liquids | ​ | ​ | 5,167 | ​ | ​ | 7,992 | ​ | ​ | (2,825) | ​ | (35.3) | %
Total revenues | ​ | ​ | 41,625 | ​ | ​ | 73,473 | ​ | ​ | (31,848) | ​ | (43.3) | %
Operating costs: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating costs: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
CO2 costs | ​ | ​ | 3,206 | ​ | ​ | 4,206 | ​ | ​ | (1,000) | ​ | (23.8) | %
Ad valorem and production taxes | ​ | ​ | 2,550 | ​ | ​ | 5,359 | ​ | ​ | (2,809) | ​ | (52.4) | %
Other lease operating costs | ​ | ​ | 18,485 | ​ | ​ | 24,592 | ​ | ​ | (6,107) | ​ | (24.8) | %
Depletion, depreciation, and accretion: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Depletion of full cost proved oil and natural gas properties | ​ | ​ | 8,148 | ​ | ​ | 6,500 | ​ | ​ | 1,648 | ​ | 25.4 | %
Accretion of asset retirement obligations | ​ | ​ | 712 | ​ | ​ | 556 | ​ | ​ | 156 | ​ | 28.1 | %
General and administrative expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
General and administrative | ​ | ​ | 4,069 | ​ | ​ | 4,351 | ​ | ​ | (282) | ​ | (6.5) | %
Stock-based compensation | ​ | ​ | 1,036 | ​ | ​ | 702 | ​ | ​ | 334 | ​ | 47.6 | %
Other income (expense): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net gain (loss) on derivative contracts | ​ | ​ | — | ​ | ​ | 243 | ​ | ​ | (243) | ​ | (100.0) | %
Interest and other income | ​ | ​ | 220 | ​ | ​ | 13 | ​ | ​ | 207 | ​ | 1,592.3 | %
Interest expense | ​ | ​ | (66) | ​ | ​ | (372) | ​ | ​ | 306 | ​ | (82.3) | %
Income tax (expense) benefit | ​ | ​ | (1,017) | ​ | ​ | (5,997) | ​ | ​ | 4,980 | ​ | (83.0) | %
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Crude oil (MBBL) | ​ | ​ | 320 | ​ | ​ | 334 | ​ | ​ | (14) | ​ | (4.2) | %
Natural gas (MMCF) | ​ | ​ | 3,976 | ​ | ​ | 4,861 | ​ | ​ | (885) | ​ | (18.2) | %
Natural gas liquids (MBBL) | ​ | ​ | 191 | ​ | ​ | 221 | ​ | ​ | (30) | ​ | (13.6) | %
Equivalent (MBOE)(1) | ​ | ​ | 1,174 | ​ | ​ | 1,365 | ​ | ​ | (191) | ​ | (14.0) | %
Average daily production (BOEPD)(1) | ​ | ​ | 6,380 | ​ | ​ | 7,418 | ​ | ​ | (1,038) | ​ | (14.0) | %
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average price per unit(2): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Crude oil (BBL) | ​ | $ | 76.17 | ​ | $ | 84.62 | ​ | $ | (8.45) | ​ | (10.0) | %
Natural gas (MCF) | ​ | ​ | 3.04 | ​ | ​ | 7.66 | ​ | ​ | (4.62) | ​ | (60.3) | %
Natural Gas Liquids (BBL) | ​ | ​ | 27.05 | ​ | ​ | 36.16 | ​ | ​ | (9.11) | ​ | (25.2) | %
Equivalent (BOE)(1) | ​ | ​ | 35.46 | ​ | ​ | 53.83 | ​ | ​ | (18.37) | ​ | (34.1) | %
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average cost per unit: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating costs: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating costs: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
CO2 costs | ​ | $ | 2.73 | ​ | $ | 3.08 | ​ | ​ | (0.35) | ​ | (11.4) | %
Ad valorem and production taxes | ​ | ​ | 2.17 | ​ | ​ | 3.93 | ​ | ​ | (1.76) | ​ | (44.8) | %
Other lease operating costs | ​ | ​ | 15.75 | ​ | ​ | 18.02 | ​ | ​ | (2.27) | ​ | (12.6) | %
Depletion of full cost proved oil and natural gas properties | ​ | ​ | 6.94 | ​ | ​ | 4.76 | ​ | ​ | 2.18 | ​ | 45.8 | %
General and administrative expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
General and administrative | ​ | ​ | 3.47 | ​ | ​ | 3.19 | ​ | ​ | 0.28 | ​ | 8.8 | %
Stock-based compensation | ​ | ​ | 0.88 | ​ | ​ | 0.51 | ​ | ​ | 0.37 | ​ | 72.5 | %

(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 $41.6 million and $73.5 million for the six months ended December 31, 2023 and 2022, respectively. The decrease in revenues is primarily due to the decrease in our average realized price per BOE coupled with a decrease in our sales volumes. Our average realized commodity price (excluding the impact of derivative contracts) for the six months ended December 31, 2023 decreased approximately $18.37 per BOE, or 34.1%, over the prior year period. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, inventory storage levels, basis differentials and other factors. Realized natural gas prices decreased 60.3% from the prior year period, driving the largest decrease in revenues. This was partially attributed to the prior year period benefit of strong natural gas price differentials received at the Jonah Field where we realized an average natural gas price of $9.59 per MCF in the prior year period compared to $4.27 in the current year period. Average daily equivalent production decreased 14.0% from 7,418 BOEPD in the prior year period to 6,380 BOEPD in the current period. We began experiencing production declines and downtime in April 2023 at Barnett. Production declines were primarily related to compression issues due to excessive heat, downtime in the gathering and processing system, pipeline rerouting and optimization, and our operator’s decision to temporarily shut-in certain low margin wells. As of December 31, 2023, the midstream issues have been moderated, but due to low natural gas prices the shut-in wells remain offline which has continued to impact production volumes.

​

Lease Operating Costs

Ad valorem and production taxes were $2.6 million and $5.4 million for the six months ended December 31, 2023 and 2022, respectively. On a per unit basis, ad valorem and production taxes were $2.17 per BOE and $3.93 per BOE for the six months ended December 31, 2023 and 2022, respectively. The decrease in ad valorem and production taxes is primarily due to decreases in oil and natural gas prices as well as decreased production volumes described above as production taxes are based on sales at the wellhead.

The following table summarizes CO2 costs per Mcf and CO2 volumes for the six months ended December 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.

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
| ​ | Six Months Ended | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, | ​ | ​ | ​ | ​ | ​ | ​
​ |  | 2023 |  | 2022 |  | Variance |  | Variance %
CO2 costs per MCF | ​ | $ | 0.98 | ​ | $ | 1.06 | ​ | $ | (0.08) | ​ | (7.5) | %
CO2 volumes (MMCF per day, gross) | ​ | ​ | 74.4 | ​ | ​ | 90.4 | ​ | ​ | (16.0) | ​ | (17.7) | %

​

The $1.0 million decrease in CO2 costs for the six months ended December 31, 2023 was primarily due to a 17.7% decrease in purchased CO2 volumes combined with a 7.5% decrease in CO2 costs per MCF, which was driven by a decrease in our average realized oil price. CO2 volumes injected were reduced compared to prior year period due to a reduction in CO2 purchase nominations and higher ambient temperatures in the Delhi Field during the current period. In the prior year period, CO2 purchase nominations were higher to compensate for reduced reservoir pressure. CO2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. We do not have any ownership in the CO2 pipeline which is owned and operated by Denbury. On a per unit basis, CO2 costs were $2.73 per BOE and $3.08 per BOE for the six months ended December 31, 2023 and 2022, respectively.

Other lease operating costs decreased $6.1 million, or 24.8%, compared to the prior year period primarily due to lower production combined with the lower commodity price environment. On a per unit basis, other lease operating costs decreased to $15.75 per BOE for the six months ended December 31, 2023 from $18.02 per BOE in the year-ago quarter. The largest decrease in operating costs is at our Barnett Shale properties and the Delhi Field. At the Barnett Shale, significant cost savings efforts are being prioritized due to the lower realized natural gas prices and the shut-in of certain low margin wells at current natural gas prices. We are incurring lower operating costs in all cost categories, especially lower water hauling costs and lower gathering, transportation and processing charges. At Delhi Field, we have seen lower electricity charges due to lower commodity prices.

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Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased $1.6 million or 25.4% from $6.5 million to $8.1 million for the six months ended December 31, 2023 primarily due to an increase in the depletion rate. On a per unit basis, depletion expense was $6.94 per BOE and $4.76 per BOE for the six months ended December 31, 2023 and 2022, respectively. The depletion rate of our unit of production calculation increased due to decreases in proved reserve volumes as well as increase in our depletable base due to capital expenditures since December 31, 2022. Our proved reserves volumes have decreased since the prior year period primarily due to oil and natural gas volumes produced combined with a reduction in the SEC prices used for calculating proved reserves since the prior year period.

General and Administrative Expenses

General and administrative expenses for the six months ended December 31, 2023 decreased $0.3 million, or 6.5%, to $4.1 million compared to $4.4 million for the prior year period. The decrease primarily relates to lower consulting fees totaling approximately $0.3 million related to our search for a CEO and outsourced services in the prior year period. On a per unit basis, general and administrative expenses were $3.47 per BOE and $3.19 per BOE for the six months ended December 31, 2023 and 2022, respectively. The slight increase on a per unit basis is primarily the result of the decrease in production for the current year period.

Stock-based Compensation Expense

Stock-based compensation expense for the six months ended December 31, 2023 increased $0.3 million to $1.0 million compared to $0.7 million for the prior year period. The increase is primarily due to the addition of new personnel, including our CEO and COO added since the prior year period and the associated new awards granted during the current year period.

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Net Gain (Loss) on Derivative Contracts

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 of December 31, 2023, we did not have any open crude oil or natural gas derivative contracts. In the prior year period, because 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 those hedges resulted in realized losses on derivative contracts for the prior year period.

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Six Months Ended | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, | ​ | ​ | ​ | ​ | ​ | ​
(in thousands, except per unit and per BOE amounts) |  | 2023 |  | 2022 |  | Variance |  | Variance %
Realized gain (loss) on derivative contracts | ​ | $ | — | ​ | $ | (1,946) | ​ | $ | 1,946 | ​ | (100.0) | %
Unrealized gain (loss) on derivative contracts | ​ | ​ | — | ​ | ​ | 2,189 | ​ | ​ | (2,189) | ​ | (100.0) | %
Total net gain (loss) on derivative contracts | ​ | $ | — | ​ | $ | 243 | ​ | $ | (243) | ​ | (100.0) | %
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average realized crude oil price per BBL | ​ | $ | 76.17 | ​ | $ | 84.62 | ​ | $ | (8.45) | ​ | (10.0) | %
Cash effect of oil derivative contracts per BBL | ​ | ​ | — | ​ | ​ | (0.73) | ​ | ​ | 0.73 | ​ | (100.0) | %
Crude oil price per BBL (including impact of realized derivatives) | ​ | $ | 76.17 | ​ | $ | 83.89 | ​ | $ | (7.72) | ​ | (9.2) | %
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average realized natural gas price per MCF | ​ | $ | 3.04 | ​ | $ | 7.66 | ​ | $ | (4.62) | ​ | (60.3) | %
Cash effect of natural gas derivative contracts per MCF | ​ | ​ | — | ​ | ​ | (0.35) | ​ | ​ | 0.35 | ​ | (100) | %
Natural gas price per MCF (including impact of realized derivatives) | ​ | $ | 3.04 | ​ | $ | 7.31 | ​ | $ | (4.27) | ​ | (58.4) | %

Interest Expense

Interest expense decreased $0.3 million for the six months ended December 31, 2023 compared to the prior year period primarily due to repayments of borrowings outstanding on our Senior Secured Credit Facility during the prior fiscal year.

Income Tax (Expense) Benefit

For the six months ended December 31, 2023, we recognized income tax expense of $1.0 million on net income before income taxes of $3.6 million compared to income tax expense of $6.0 million on net income before income taxes of $27.1 million for the six months ended December 31, 2022. The effective tax rates were 28.5% and 22.1% for three months ended December 31, 2023 and 2022, respectively. The effective tax rate increased compared to the prior year period as projected state income taxes have become a larger component of our overall income tax expense during the period.

Critical Accounting Policies and Estimates

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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risks

Derivative Instruments and Hedging Activity

We are exposed to various risks, including energy commodity price risk, such as price differentials between the NYMEX commodity price and the index price at the location where our production is sold. When oil, natural gas, and natural gas liquids prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we monitor commodity prices to identify the potential need for the use of derivative financial instruments to provide partial protection against declines in oil and natural gas prices. We do not enter into derivative contracts for speculative trading purposes.

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 6, “Derivatives” to our unaudited condensed consolidated financial statements for more details.

Interest Rate Risk

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

Item 4. Controls and Procedures

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

As required by SEC Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15(d)-15(e)) as of the end of the quarter covered by this report. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. Based on the foregoing, our Principal Executive Officer and Principal Financial Officer concluded that as of December 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 December 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 control over financial reporting.

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Part II. OTHER INFORMATION

Item 1. Legal Proceedings

See Note 9, “Commitments and Contingencies” to our unaudited condensed consolidated financial statements in Item 1. Condensed Consolidated Financial Statements (Unaudited) for a description of any legal proceedings, which is incorporated herein by reference.

Item 1A. Risk Factors

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

​

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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 December 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)
October 2023 | ​ | — | ​ | $ | — | ​ | — | ​ | $ | 21,152
November 2023 | ​ | 17,436 | ​ | ​ | 6.20 | ​ | — | ​ | ​ | 21,152
December 2023 | ​ | — | ​ | ​ | — | ​ | — | ​ | ​ | 21,152

(1) | During the three months ended December 31, 2023, all of the shares received were surrendered by employees in exchange for the payment of tax withholding upon the vesting of restricted stock awards.

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

​

Item 3. Defaults Upon Senior Securities

Not Applicable.

Item 4. Mine Safety Disclosures

Not Applicable.

​

Item 5. Other Information

N o n e.

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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.

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​ | ​ | ​
​ | ​ | ​
​ | ​ | ​
​ | ​ | ​
​ | ​ | ​
​ | ​ | ​
​ | ​ | ​
3.1 | ​ | Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 of our Quarterly Report on Form 10-Q filed February 8, 2023).
3.3 | ​ | Amended and Restated Bylaws (incorporated by reference to Exhibit 3.3 of our Annual Report on Form 10- filed September 13, 2023)
31.1** | ​ | Certification of Principal Executive Officer Pursuant to Rule 15D-14 of the Securities Exchange Act of 1934, as Amended as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2** | ​ | Certification of Principal Financial Officer Pursuant to Rule 15D-14 of the Securities Exchange Act of 1934, as Amended as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1** | ​ | Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2** | ​ | Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS* | ​ | Inline XBRL Instance Document
101.SCH* | ​ | Inline XBRL Taxonomy Extension Schema Document
101.CAL* | ​ | Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* | ​ | Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* | ​ | Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE* | ​ | Inline XBRL Taxonomy Extension Presentation Linkbase Document
104* | ​ | Cover Page Interactive Data File (embedded within the Inline XBRL document)

* Attached hereto.

** Furnished herewith.

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Table of Contents

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: February 7, 2024 | ​ | By: | /s/ KELLY W. LOYD
​ | ​ | ​ | Kelly W. Loyd President and Chief Executive Officer (Principal Executive Officer) and Director ​ ​
​ | ​ | By: | /s/ RYAN STASH
​ | ​ | ​ | Ryan Stash Senior Vice President and Chief Financial Officer (Principal Financial Officer) and Treasurer ​

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