SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


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

For the quarterly period ended December 31, ~~2017~~

Commission File Number 001-32942

CORPORATION

(Exact name of registrant as specified in its charter)

1155 Dairy Ashford Road, Suite 425, Houston, Texas77079

(Address of principal executive offices and zip code)

~~(713)~~

(713) 935-0122

(Registrant’s telephone number, including area code)

~~(Former name, former address and former fiscal year if changed since last report)~~

Title of Each Class

Trading Symbol(s)

Name of Each Exchange On Which Registered

Common Stock, $0.001 par value

Large accelerated filer o

Non-accelerated filer

Smaller reporting company

~~Non-accelerated filer~~ o ~~(Do not check if a smaller reporting company)~~

Emerging growth companyo

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. o

☐

Table of ~~February 5, 2018, was 33,171,514.~~Contents

EVOLUTION PETROLEUM CORPORATION ~~AND SUBSIDIARIES~~

TABLE OF CONTENTS



		~~Page~~

~~PART I. FINANCIAL INFORMATION~~		2
Forward-Looking Statements			2
~~ITEM 1.~~PART I .	~~UNAUDITED CONSOLIDATED CONDENSED~~ FINANCIAL ~~STATEMENTS~~INFORMATION	2 4
Item 1.	Condensed Consolidated Financial Statements (Unaudited)	4
	~~Unaudited~~Condensed Consolidated ~~Condensed~~ Balance Sheets (Unaudited) as of December 31, ~~2017~~2023 and June 30, ~~2017~~2023	2 4
	~~Unaudited~~Condensed Consolidated ~~Condensed~~ Statements of Operations (Unaudited) for the three and six months ended December 31, ~~2017~~2023 and ~~2016~~2022	3 5
	~~Unaudited~~Condensed Consolidated ~~Condensed~~ Statements of Cash Flows (Unaudited) for the six months ended December 31, ~~2017~~2023 and ~~2016~~2022	4 6
	~~Unaudited~~Condensed Consolidated ~~Condensed Statement~~Statements of Changes in Stockholders’ Equity (Unaudited) for the three and six months ended December 31, ~~2017~~2023 and 2022	5 7
	Notes to Unaudited Condensed Consolidated ~~Condensed~~ Financial Statements	6 8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
~~ITEM 2.~~Item 3.	~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~Quantitative and Qualitative Disclosures about Market Risks	16 37
Item 4.	Controls and Procedures	37
~~ITEM 3.~~		~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~	25

~~ITEM 4.~~	~~CONTROLS AND PROCEDURES~~	25

PART II. OTHER INFORMATION		26 38
Item 1.	Legal Proceedings	38
~~ITEM 1.~~Item 1A.	~~LEGAL PROCEEDINGS~~Risk Factors	26 38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
~~ITEM 1A.~~Item 3.	~~RISK FACTORS~~Defaults Upon Senior Securities	26 39
Item 4.	Mine Safety Disclosures	39
~~ITEM 2.~~Item 5.	~~UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS~~Other Information	26 39
Item 6.	Exhibits	40
~~ITEM 3.~~	~~DEFAULTS UPON SENIOR SECURITIES~~Signatures	26

~~ITEM 4.~~	~~MINE SAFETY DISCLOSURES~~	27

~~ITEM 5.~~	~~OTHER INFORMATION~~	27

~~ITEM 6.~~	~~EXHIBITS~~	27

~~SIGNATURES~~		27 41

~~PART I — FINANCIAL INFORMATION~~

~~ITEM 1. CONSOLIDATEDCONDENSEDFINANCIAL STATEMENTS~~

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

~~Consolidated Condensed Balance Sheets~~

~~(Unaudited)~~

December 31,
2017 June 30,
2017
Assets

Current assets

Cash and cash equivalents $ 25,743,497
$ 23,028,153
Receivables 4,078,153
2,726,702
Prepaid expenses and other current assets 824,048
387,672
Total current assets 30,645,698
26,142,527
Oil and natural gas property and equipment, net (full-cost method of accounting) 60,093,807
61,790,068
Other property and equipment, net 32,265
40,689
Total property and equipment 60,126,072
61,830,757
Other assets 260,468
295,384
Total assets $ 91,032,238
$ 88,268,668
Liabilities and Stockholders’ Equity

Current liabilities

Accounts payable $ 2,400,202
$ 1,994,255
Accrued liabilities and other 660,467
724,639
Total current liabilities 3,060,669
2,718,894
Long term liabilities

Deferred income taxes 10,580,381
15,826,291
Asset retirement obligations 1,297,028
1,253,628
Total liabilities 14,938,078
19,798,813
Commitments and contingencies (Note 14)

Stockholders’ equity

Common stock; par value $0.001; 100,000,000 shares authorized; 33,171,514 and 33,087,308 shares issued and outstanding as of December 31, 2017 and June 30, 2017, respectively 33,171
33,087
Additional paid-in capital 41,538,133
40,961,957
Retained earnings 34,522,856
27,474,811
Total stockholders’ equity 76,094,160
68,469,855
Total liabilities and stockholders’ equity $ 91,032,238
$ 88,268,668

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FORWARD-LOOKING STATEMENTS

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

●

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

●

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

●

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

●

our ability to maximize cash flow and the application of excess cash flows to pay dividends and repurchase shares pursuant to our share repurchase program;

●

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.

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.

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 ~~condensed~~ financial statements.

~~Evolution Petroleum Corporation and Subsidiaries~~

~~Consolidated Condensed Statements of Operations~~

Three Months Ended
December 31, Six Months Ended
December 31,
2017 2016 2017 2016
Revenues

Crude oil $ 10,185,635
$ 8,529,817
$ 18,014,890
$ 16,123,672
Natural gas liquids 881,276
—
1,589,892
89
Natural gas —
—
—
(4 )
Total revenues 11,066,911
8,529,817
19,604,782
16,123,757
Operating costs
Production costs 2,914,512
2,292,421
5,806,098
4,637,062
Depreciation, depletion and amortization 1,633,868
1,307,510
3,152,411
2,580,949
Accretion of discount on asset retirement obligations 23,023
13,106
44,602
26,330
General and administrative expenses * 1,666,256
1,241,399
3,235,960
2,476,442
Total operating costs 6,237,659
4,854,436
12,239,071
9,720,783
Income from operations 4,829,252
3,675,381
7,365,711
6,402,974
Other

Gain on realized derivative instruments, net —
—
—
90
Loss on unrealized derivative instruments, net —
—
—
(14,132 )
Interest and other income 15,841
14,061
30,691
26,806
Interest expense (20,456 ) (20,711 ) (40,911 ) (41,056 )
Income before income taxes 4,824,637
3,668,731
7,355,491
6,374,682
Income tax provision (benefit) (5,052,211 ) 1,361,097
(4,661,889 ) 2,250,273
Net income attributable to the Company 9,876,848
2,307,634
12,017,380
4,124,409
Dividends on preferred stock —
—
—
250,990
Deemed dividend on redeemed preferred shares —
—
—
1,002,440
Net income available to common stockholders $ 9,876,848
$ 2,307,634
$ 12,017,380
$ 2,870,979
Earnings per common share
Basic $ 0.30
$ 0.07
$ 0.36
$ 0.09
Diluted $ 0.30
$ 0.07
$ 0.36
$ 0.09
Weighted average number of common shares

Basic 33,109,448
33,047,166
33,099,546
33,002,088
Diluted 33,140,278
33,083,027
33,140,257
33,037,269

* General and administrative expenses for the three months ended December 31, 2017 and 2016 included non-cash stock-based compensation expense of $484,326 and $275,184, respectively. For the corresponding six month periods, non-cash stock-based compensation expense was $971,810 and $586,872, respectively.

~~Evolution Petroleum Corporation and Subsidiaries~~

~~Consolidated Condensed Statements of Cash Flows~~

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 ~~condensed~~ financial statements.

~~Evolution Petroleum Corporation and Subsidiaries~~

~~Consolidated Condensed Statement of Changes in Stockholders' Equity~~

~~For the Six Months Ended December 31, 2017~~

Common Stock
Additional
Paid-in
Capital Retained
Earnings Treasury
Stock Total
Stockholders'
Equity
Shares Par Value
Balance at June 30, 2017 33,087,308
$ 33,087
$ 40,961,957
$ 27,474,811
$ —
$ 68,469,855
Issuance of restricted common stock 158,785
158
(158 ) —
—
—
Forfeitures of restricted stock (19,561 ) (20 ) 20
—
—
—
Common share repurchases, including shares surrendered for tax withholding (55,018 ) —
—
—
(395,550 ) (395,550 )
Retirements of treasury stock —
(54 ) (395,496 ) —
395,550
—
Stock-based compensation —
—
971,810
—
—
971,810
Net income attributable to the Company —
—
—
12,017,380
—
12,017,380
Common stock cash dividends —
—
—
(4,969,335 ) —
(4,969,335 )
Balance at December 31, 2017 33,171,514
$ 33,171
$ 41,538,133
$ 34,522,856
$ —
$ 76,094,160

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 ~~condensed~~ 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 ~~And Subsidiaries~~

~~Notes to Unaudited Consolidated Condensed Financial Statements~~

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

producing leasehold, geologic and geophysical costs associated with leasehold or drilling interests, and exploration drilling costs. These costs are excluded until the project is evaluated and proved reserves are established or impairment is determined. 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 usthe 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 ~~dates~~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 ~~depreciation,~~ depletion ~~and amortization~~ 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, ~~and~~ (f) commitments and ~~contingencies. We analyze our~~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 ~~we believe~~are believed to be reasonable. ~~While we believe that our~~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 are appropriate, actual results could differ from those estimates.~~

~~New~~statements.

Recently Issued Accounting ~~Pronouncements.~~

Pronouncements

In ~~August 2015,~~December 2023, the ~~Financial Accounting Standards Board ("FASB")~~FASB issued ~~Accounting Standards Update 2015-14, which defers~~ASU 2023-09, Improvements to Income Tax Disclosures (“ASU 2023-09”). ASU 2023-09 enhances the ~~effective date~~transparency of income tax disclosures by expanding the income tax rate reconciliation disclosure and income taxes paid information. ASU ~~2014-09~~ ~~Revenue from Contracts with Customers (Topic 606) ("~~2023-09 also includes certain other amendments to improve the effectiveness of income tax disclosures. ASU 2014-09") by one year and allows entities the option to early adopt the new revenue standard as of the original effective date. Issued in May 2014, ASU 2014-09 provided guidance on revenue recognition on contracts with customers to transfer goods or services or on contracts for the transfer of nonfinancial assets. ASU 2014-09 requires that revenue recognition on contracts with customers depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. For public companies, ASU 2014-092023-09 is ~~now~~ effective for ~~fiscal years, and interim~~annual periods ~~within those years,~~ beginning after December 15, ~~2017. The standard provides for either the full retrospective or modified retrospective transition methods. We expect to adopt this standard using the modified retrospective method.~~2024. The Company ~~expects that additional disclosures will be required as a result of adopting ASU 2014-09 and~~ is currently ~~assessing~~evaluating ASU 2023-09 and the impact it may have to the Company’s financial position, results of ~~the guidance on its consolidated financial statements.~~

operations, cash flow or disclosures.

In ~~January~~June 2016, the FASB issued ASU ~~2016-01,~~2016-13, Financial Instruments - ~~Overall: Recognition and Measurement of Financial Assets and Financial Liabilities~~ ("Credit Losses (“ASU ~~2016-01"~~2016-13”). ~~The pronouncement requires equity investments (except those accounted~~ASU 2016-13 changes the impairment model for under the equity method of accounting, or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income, requires public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes, requires separate presentation ofmost financial assets and ~~financial liabilities~~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 ~~measurement category~~ASU 2019-10, Financial Instruments - Credit Losses (Topic 326), Derivatives and ~~form of financial asset,~~Hedging (Topic 815), and ~~eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value that~~Leases (Topic 842), ASU 2016-13 is ~~required to be disclosed for financial instruments measured at amortized cost. These changes become~~ effective for ~~fiscal years~~annual periods, including interim periods within those annual periods, beginning after December 15, ~~2017.~~2022. The ~~expected~~Company adopted ASU 2016-13 effective July 1, 2023. The adoption ~~method~~did not have a material effect on the Company’s financial position, results of ~~ASU 2016-01 is being evaluated~~operations, cash flows or disclosures.

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

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~Evolution Petroleum Corporation And Subsidiaries~~

~~Notes~~

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 ~~Unaudited Consolidated Condensed Financial Statements~~

~~In February 2016,~~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 ~~FASB issued ASU 2016-02 ,~~ ~~Leases~~ ~~(“ASU 2016-02”~~point in time when custody and title (“control”)~~, which relates~~ of the product transfers to the ~~accounting for leasing transactions. This standard requires a lessee~~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 ~~record on the balance sheet the assets~~local indices and liabilities for the rights and obligations created by leases with lease terms of more than twelve months. In addition, this standard requires both lessees and lessors to disclose certain key information about lease transactions. This standard will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We are evaluating the impact the adoption of ASU 2016-02 will have on our consolidated financial statements.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classifiedvolumes delivered in the ~~statement~~current month. The Company receives payment from the sale of ~~cash flows.~~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 ~~guidance addresses eight specific cash flow issues for which current GAAP is either unclear or~~Company does not ~~include specific guidance. This standard will be effective for fiscal years beginning after December 15, 2017,~~believe that significant judgments are required with respect to the determination of the transaction price, including ~~interim periods within those fiscal years~~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 ~~early adoption permitted, provided that it is adopted in its entirety in the same period. Currently,~~predictable differentials. Accordingly, the Company does not ~~expect~~consider estimates of variable consideration to be constrained.

The Company’s contractual performance obligations arise upon the ~~impact~~production of ~~adopting ASU 2016-15~~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 ~~a material effect~~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 ~~its~~the unaudited condensed consolidated ~~statements~~balance sheets.

Table of ~~cash flows.~~Contents

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 ~~2 — Receivables~~

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, ~~2017~~2023, $3.4 million of oil and ~~June 30, 2017, our receivables consisted~~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 ~~following:~~

December 31,
2017 June 30,
2017
Receivables from oil and gas sales $ 4,078,153
$ 2,722,880
Other —
3,822
Total receivables $ 4,078,153
$ 2,726,702

~~Note 3 — Prepaid Expenses~~initial nine development wells, the Company will have the right, but not the obligation, to elect to participate and ~~Other Current Assets~~

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, ~~2017~~2023, the Company has incurred approximately $3.0 million in capital expenditures related to the drilling and ~~June 30, 2017, our prepaid expenses~~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 ~~other current assets consisted~~natural gas properties. All costs of acquisition, exploration, and development of oil and natural gas reserves are capitalized as the ~~following:~~

December 31,
2017 June 30,
2017
Prepaid insurance $ 86,904
$ 169,416
Retainers and deposits 7,589
7,553
Prepaid federal and state income taxes 674,028
121,232
Other prepaid expenses 55,527
89,471
Prepaid expenses and other current assets $ 824,048
$ 387,672

~~Table~~cost of ~~Contents~~

~~Evolution Petroleum Corporation And Subsidiaries~~

~~Notes to Unaudited Consolidated Condensed Financial Statements~~

~~Note 4 —Property and Equipment~~

~~As of December 31, 2017 and June 30, 2017, our~~ oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and ~~other~~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 ~~equipment consisted~~all or a portion of the ~~following:~~

December 31,
2017 June 30,
2017
Oil and natural gas properties

Property costs subject to amortization $ 86,403,877
$ 84,962,933
Less: Accumulated depreciation, depletion, and amortization (26,310,070 ) (23,172,865 )
Unproved properties not subject to amortization —
—
Oil and natural gas properties, net $ 60,093,807
$ 61,790,068
Other property and equipment

Furniture, fixtures, office equipment and other, at cost $ 135,377
$ 135,377
Less: Accumulated depreciation (103,112 ) (94,688 )
Other property and equipment, net $ 32,265
$ 40,689

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, ~~2017~~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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EVOLUTION PETROLEUM CORPORATION

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 ~~incurred capital expenditures~~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 ~~$1.4 million~~$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 ~~$6.5 million, respectively,~~modifies the Margined Collateral Value, as defined in the ~~Delhi field.~~

~~Note 5~~—~~Other Assets~~

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, ~~2017~~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, ~~2017,~~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 ~~consisted~~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 ~~following:~~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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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

December 31,
2017 June 30,
2017
Royalty rights $ 108,512
$ 108,512
Less: Accumulated amortization of royalty rights (27,128 ) (20,346 )
Investment in Well Lift Inc., at cost 108,750
108,750
Deferred loan costs 168,972
168,972
Less: Accumulated amortization of deferred loan costs (98,638 ) (70,504 )
Other assets, net $ 260,468
$ 295,384

~~Our royalty rights~~

call, which establishes a maximum price the Company will receive for the volumes under contract, and ~~investment~~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 ~~Well Lift, Inc. ("WLI") resulted from~~ the separation of our artificial lift technology operations in December 2015. We conveyed our patents and other intellectual property to WLI and retained a 5% royalty on future gross revenues associated the technology. We own 17.5%mark-to-market valuation of the ~~common stock~~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 ~~WLI and account for our investment under the cost method. Any dividends paid~~operations.

All derivative contracts are recorded ~~as income~~at fair market value in accordance with ASC 815, Derivatives and ~~any return~~Hedging (“ASC 815”) and ASC 820, Fair Value Measurement (“ASC 820”). The following table summarizes the location and amounts of ~~capital reduces our cost basis~~the Company’s realized and unrealized gains and losses on derivative contracts in the ~~investment. Our investment~~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 ~~WLI~~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 ~~evaluated~~a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for ~~impairment~~offsetting of amounts payable or receivable between the Company and the counterparty, at ~~least quarterly~~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 ~~when management identifies~~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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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 ~~events~~period presented in this report. The Company did not have any open positions at December 31, 2023 or ~~changes~~June 30, 2023.

Other Fair Value Measurements. The following disclosure of the estimated fair value of financial instruments is made in ~~circumstances that might~~accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have ~~a significant adverse effect~~been determined at discrete points in time based on ~~the~~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 ~~investment. There is no published~~Company’s Senior Secured Credit Facility approximates carrying value because the interest rates approximate current market ~~value~~rates.

The Company follows the provisions of ASC 820, for ~~this private investment, so it is not practicable to value it~~nonfinancial assets and liabilities measured at fair ~~market~~ value on a ~~periodic~~non-recurring basis.

~~Table~~ These provisions apply to the Company’s initial measurement and any subsequent revision of ~~Contents~~

~~Evolution Petroleum Corporation And Subsidiaries~~

~~Notes to Unaudited Consolidated Condensed Financial Statements~~

~~Note 6~~—~~Accrued Liabilities and Other~~

~~As of December 31, 2017 and June 30, 2017, our other current liabilities consisted of the following:~~

December 31,
2017 June 30,
2017
Accrued incentive and other compensation $ 292,382
$ 413,113
Accrued severance payments 46,719
—
Asset retirement obligations due within one year 35,539
35,115
Accrued royalties, including suspended accounts 11,524
17,708
Accrued franchise taxes 82,800
150,062
Accrued ad valorem taxes 191,503
108,641
Accrued liabilities and other $ 660,467
$ 724,639

~~Note 7~~—~~Asset Retirement Obligations~~

~~Our~~ asset retirement obligations ~~represent~~(“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 ~~we expect~~expected to ~~incur~~be incurred to plug, abandon, and remediate ~~our producing~~its oil and natural gas properties at the end of their productive lives in accordance with applicable ~~laws.~~ 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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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following is a reconciliation of the ~~beginning and ending asset retirement obligations~~activity related to the Company’s ARO liability (inclusive of the current portion) for the ~~six months~~period ended December 31, ~~2017~~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 ~~for~~Contingencies

The Company is subject to various claims and contingencies in the ~~year ended June 30, 2017:~~

December 31,
2017 June 30,
2017
Asset retirement obligations — beginning of period $ 1,288,743
$ 962,196
Liabilities incurred —
52,792
Liabilities settled —
(157,164 )
Liabilities sold —
(47,817 )
Accretion of discount 44,602
59,664
Revision of previous estimates (778 ) 419,072
Asset retirement obligations — end of period $ 1,332,567
$ 1,288,743
Less current portion in accrued liabilities (35,539 ) (35,115 )
Long-term portion of asset retirement obligations $ 1,297,028
$ 1,253,628

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 ~~8 —~~10. Stockholders’ Equity

Common Stock

As of December 31, ~~2017, we~~2023, the Company had ~~33,171,514 shares~~33,506,794 shares of common stock outstanding.

The Company began paying quarterly cash dividends on common stock in December 2013. WeAs of December 31, 2023, the Company has cumulatively paid over $110.4 million in cash dividends. The Company paid dividends of ~~$4,969,335~~$8.0 million and ~~$3,801,962~~$8.1 million to ~~our~~its common ~~shareholders~~stockholders during the six months ended December 31, ~~2017~~2023 and ~~2016,~~2022, respectively. ~~These dividend payments consisted of two quarterly~~The following table reflects the dividends ~~of $0.075~~paid per share ~~each during~~within the ~~six months ended December 31, 2017 and quarterly dividend payments of $0.05 and $0.065 per share during the six months ended December 31, 2016.~~

~~In May 2015,~~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, ~~covering~~under which the Company is authorized to repurchase up to $5$25.0 million of ~~the Company's~~its common ~~stock. Between June 2015 and December 2015, the Company spent $1,609,008 to repurchase 265,762 common shares at an average price of $6.05 per share. There have been no shares repurchased~~stock in the open market ~~since~~through December ~~2015. Under~~31, 2024. The Company intends to fund repurchases from working capital and cash provided by operating activities. The Board of Directors along with the ~~program's terms,~~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 ~~are~~may be repurchased ~~only on the~~from time to time in open market ~~and~~transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the ~~requirements~~number and value of shares repurchased under the program, will depend on a variety of factors, including management’s assessment of the ~~Securities~~intrinsic value of the Company’s shares, the market price of the Company’s common stock, the Company’s capital needs and ~~Exchange Commission. Such shares are initially recorded as treasury stock, then subsequently canceled. The timing and amount of repurchases depends upon several factors, including financial~~ resources, ~~and~~general market and ~~business conditions. There is no fixed termination date~~economic conditions, and applicable legal requirements. The value of shares authorized for ~~this~~ repurchase ~~program,~~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 itthe program may be suspended, modified, or discontinued at any ~~time.~~time without prior notice.

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~Evolution Petroleum Corporation And Subsidiaries~~

~~Notes~~

In November 2023, the Company entered into a Rule 10b5-1 plan that authorizes a broker to ~~Unaudited Consolidated Condensed Financial Statements~~

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, ~~2017~~2023 and ~~2016,~~2022, the Company acquired treasury stock ~~from holders~~upon the ordinary course of ~~newly vested~~scheduled vestings of employee stock-based awards to fund ~~the recipients'~~ payroll tax withholding obligations. ~~The~~These treasury shares were subsequently ~~canceled.~~cancelled. Such shares were valued at fair market value on the date of ~~vesting, as reflected in the~~vesting.

The following ~~table:~~

~~In September 2016, the Company announced the decision to redeem~~table summarizes all 317,319 outstanding shares of its 8.5% Series A Cumulative Preferred Stock. The redemption occurred in November 2016 at the stated value of $25.00 per share plus all accumulated and unpaid distributions, for an aggregate redemption cost of $7,932,975.

On September 30, 2016, in connection with the planned redemption, the Company recorded a deemed dividend of $1,002,440, representing the difference between the redemption consideration paid and the historical net issuance proceeds of the preferred shares. Accordingly, net income was adjusted for this deemed dividend to determine net income attributable to common shareholders and earnings per common share.

~~Dividends on the Series A Cumulative Preferred Stock were paid at a fixed rate of 8.5% per annum on the $25.00 per share liquidation preference, payable monthly. During~~treasury stock purchases during the six months ended December 31, ~~2016, we paid cash dividends of $250,990 to holders of our Series A Preferred Stock prior to the November 2016 redemption date.~~

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, ~~2017,~~2023, all ~~preferred and~~ common stock dividends for that fiscal year were treated for tax purposes as qualified dividend income to the recipients. Based on ~~our~~its current projections for the fiscal year ~~ending~~ended June 30, ~~2018, we expect~~2024, the Company expects all common stock dividends for such period to be treated as qualified dividend ~~income.~~income to the recipients. Such projections are based on ~~our~~the Company’s reasonable expectations as of December 31, ~~2017~~2023 and are subject to change based on ~~our~~the Company’s final tax calculations at the end of the fiscal year.

~~Note 9 —~~

Stock-Based Incentive Plan

~~At the December 8, 2016 annual meeting, the stockholders approved the adoption of the~~

The Evolution Petroleum Corporation 2016 Equity Incentive Plan ~~(the~~(as amended, the “2016 Plan”)~~, which replaced the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the "2004 Plan"). The 2016 Plan~~ authorizes the issuance of ~~1,100,000~~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, ~~our~~the Company’s common stock, including its appreciation in value. As of December 31, ~~2017, 987,845~~2023 and June 30, 2023, approximately 0.9 million shares and 1.3 million shares, respectively, remained available for grant under the 2016 Plan.

~~At December 8, 2016, there were no shares available~~

The Company estimates the fair value of stock-based compensation awards on the grant date to provide the basis for future ~~grants under~~compensation expense. During the ~~2004 Plan. All outstanding awards granted under~~three and six months ended December 31, 2023, the ~~2004 Plan continue~~Company recognized $0.6 million and $1.0 million, respectively, related to ~~be subject~~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 ~~terms and conditions as set forth in the agreements evidencing such awards and the terms~~unaudited condensed consolidated statements of ~~the 2004 Plan. Under these agreements, we have outstanding grants of~~operations.

Time-Vested Restricted Stock Awards

Time-vested restricted ~~common~~ stock awards ~~("Restricted Stock")~~contain service-based vesting conditions and ~~contingent restricted common stock awards ("Contingent Restricted Stock") to employees and directors of the Company.~~

~~Restricted Stock and Contingent Restricted Stock~~

~~The Company awards grants of both Restricted Stock and Contingent Restricted Stock as part of its long-term incentive plan. Such grants, which~~ expire after a maximum of four years from the date of grant if ~~unvested, contain service-based, performance-based and market-based vesting provisions.~~unvested. The common shares underlying ~~the Restricted Stock grants~~these awards are issued on the date of ~~grant. Contingent Restricted Stock grants vest only upon~~grant and participate in dividends paid by the ~~attainment of higher performance-based or market-based vesting~~

~~Table of Contents~~

~~Evolution Petroleum Corporation And Subsidiaries~~

~~Notes to Unaudited Consolidated Condensed Financial Statements~~

~~Service-based~~Company. These service-based awards vest with continuous employment by the Company, generally in annual installments over ~~a four-year~~terms of three to four years. Awards to the Company’s directors

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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. ~~Certain awards contain other~~Previously recognized amortization expense subsequent to the last vesting ~~periods, including quarterly installments and one-year 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 ~~grants which vest~~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 ~~service~~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 ~~valued at the fair market value~~issued on the date of grant and ~~amortized over~~participate in dividends paid by the ~~service period. During~~Company and expire after a maximum of four years from the ~~six months ended December 31, 2017, we granted 112,155 service-based Restricted Stock awards, including 45,211 awards to employees~~date of grant if unvested. Performance-based contingent share units do not participate in dividends and ~~66,944 awards to directors, substantially all of which have a one-year vesting period. We did not grant any performance-based~~shares are only issued in part or ~~market based awards, nor any Contingent Restricted Stock awards, during this period.~~

~~Performance-based grants vest~~in full upon the attainment of ~~earnings, revenue~~vesting conditions, generally have a lower probability of achievement and ~~other operational goals~~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 ~~require that~~contingent restricted stock units are valued using a Monte Carlo simulation and geometric Brownian motion techniques applied to the ~~recipient remain an employee or director~~historical volatility of the Company’s total stock return compared to the historical volatilities of other companies or indices to which the Company ~~through~~compares its performance and/or the Company’s absolute total stock return. For certain awards, this Monte Carlo simulation also provides an expected vesting ~~date. The Company recognizes~~term. Stock-based compensation ~~expense for performance-based awards~~is recognized ratably over the expected vesting period, ~~based~~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 ~~grant date fair value when it is deemed probable, for accounting purposes, that~~future price of the performance criteria will be achieved. The expected vesting period may be deemed to be shorter than the four-year term. As of December 31, 2017, certain contingent performance-based awards were not considered probable of vesting for accounting purposes and no compensation expense has been recognized with regard to these awards. If these awards are later determined to be probable of vesting, cumulative compensation expense would be recorded at that time and amortization would continue over the remaining expected vesting period.

~~Market-based~~Company’s common stock. Such awards vest in part or in full if the ~~three-year~~ trailing total ~~return~~returns on the Company’s common stock ~~exceeds~~for a specified three-year period exceed the corresponding total returns of various quartiles of indices consisting of ~~either~~ peer companies or, in some cases, vest when the average of the Company’s closing common stock price over a ~~broad market index~~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 ~~companies~~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 ~~our industry. The fair values and expected vesting periods of these awards are determined using a~~the Monte Carlo simulation ~~based on the historical volatility~~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%

Table of ~~the Company's total return compared to the historical volatilities~~Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unvested restricted stock awards as of the other companies in the index. Compensation expense for market-based awards is recognized over the expected vesting period using the straight-line method, so long as the holder remains an employee or director of the Company. Total compensation expense is based on the fair value of the awards at the date of grant and is independent of vesting or expiration of the awards, except for termination of service.

~~Unvested Restricted Stock awards at~~ December 31, ~~2017~~2023 consisted of the following:

Number of
Restricted
Shares Weighted
Average
Grant-Date
Fair Value
Service-based awards 220,068
$ 6.68
Performance-based awards 50,360
5.67
Market-based awards 50,359
5.44
Unvested Restricted Stock at December 31, 2017 320,787
$ 6.33


		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~~restricted stock award transactions for the six months ended December 31, ~~2017:~~

Number of
Restricted
Shares Weighted
Average
Grant-Date
Fair Value Unamortized Compensation Expense at December 31, 2017 Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2017 391,624
$ 6.22

Service-based shares granted 112,155
6.96

Vested (163,431 ) 6.52

Forfeited (19,561 ) 6.16

Unvested Restricted Stock at December 31, 2017 320,787
$ 6.33
$ 1,510,203
1.39

~~Table of Contents~~

~~Evolution Petroleum Corporation And Subsidiaries~~

~~Notes to Unaudited Consolidated Condensed Financial Statements~~

~~Unvested Contingent Restricted Stock awards at December 31, 2017 consisted of the following:~~

Number of
Contingent
Restricted
Shares Weighted
Average
Grant-Date
Fair Value
Performance-based awards 36,688
$ 7.04
Market-based awards 25,180
3.42
Unvested contingent shares at December 31, 2017 61,868
$ 5.57

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~~contingent restricted stock unit transactions for the six months ended December 31, ~~2017:~~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

~~(1) Excludes $115,665 of potential future compensation expense for contingent performance-based awards for which vesting is not considered probable at this time for accounting purposes.~~

Stock-based compensation expense related to Restricted Stock and Contingent Restricted Stock grants for the three months ended December 31, 2017 and 2016 was $484,326 and $275,184, respectively. For the corresponding six month periods, non-cash stock compensation expense was $971,810 and $586,872, respectively.

From time to time, the Company may use derivative instruments to reduce its exposure to crude oil price volatility of its near-term forecasted production. The Company's objectives are to achieve a more predictable level of cash flows to support the Company’s capital expenditure programs and to provide better financial visibility for the payment of dividends on common stock. The Company may use both fixed price swap agreements and costless collars to manage its exposure to crude oil and other commodity price risk. While these derivative instruments are intended to limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The Company does not intend to enter into derivative instruments for speculative or trading purposes.

~~The Company accounts for derivatives under the provisions of ASC 815~~ ~~Derivatives and Hedgin~~g ("ASC 815") under which the Company records the fair value of the instruments on the balance sheet at each reporting date, with changes in fair value recognized in other non-operating income and expense. Given the cost and complexity, the Company has elected not to use cash flow hedge accounting provided under ASC 815. Under cash flow hedge accounting, a portion of the change in fair value of the derivative instruments, if effective in hedging the underlying commodity risk, would be deferred in other comprehensive income and recognized in earnings only when the underlying hedged item impacts earnings.

These derivative instruments can result in both fair value asset and liability positions held with each counterparty. These positions are offset to a single net fair value asset or liability at the end of each reporting period. The Company nets its fair value amounts of derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. As of June 30, 2017 and December 31, 2017, the Company had no derivative asset or liability positions.

The Company monitors the credit rating of its counterparties and believes it does not have significant credit risk. Accordingly, we do not currently require our counterparties to post collateral to support the net asset positions of our derivative instruments. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties to its derivative instruments.

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~~Evolution Petroleum Corporation And Subsidiaries~~

~~Notes to Unaudited Consolidated Condensed Financial Statements~~

For the six months ended December 31, 2017, the Company had no gains or losses from derivatives. For the six months ended December 31, 2016, the Company recorded a loss on derivative instruments of $14,042 consisting of a realized gain of $90 on settled positions and an unrealized net loss of $14,132.

EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 11—~~Income Taxes~~

~~We file a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions.~~

On December 22, 2017, the U.S. government enacted comprehensive tax legislation under the title of the Tax Cuts and Jobs Act ("Tax Act"). The Tax Act includes a permanent reduction in our federal corporate income tax rate from 34% to 21%. It also provides more favorable tax deductions associated with capital investments and other significant changes to tax law. The Tax Act became effective upon passage, so our statutory rate for the current fiscal year ending June 30, 2018 is a blended rate of 27.55%. The permanent reduction in the federal corporate income tax rate resulted in a one-time non-cash income tax benefit of approximately $6.0 million related to the adjustment of our liability for deferred income taxes to the lower rate in the Tax Act. The accounting for the effects of the rate change on the Company’s deferred tax balances is complete and no provisional amounts were recorded.

Income taxes are recorded in our financial statements based on our estimated annual effective income tax rate. The effective rates used in the calculation of our income tax expense were approximately 20% and 35% for the six months ended December 31, 2017 and 2016, respectively. After adjustment for the $6.0 million discrete benefit resulting from the revaluation of our deferred income tax liabilities, the effective rate for the six months ended December 31, 2017 was a tax benefit of (63)% of income before income taxes.

Our effective tax rate will typically differ from the statutory federal rate as a result of state income taxes, primarily in the State of Louisiana, and differences related to percentage depletion in excess of basis, stock-based compensation and other permanent differences. The effective tax rate for the six months ended December 31, 2017 was significantly lower than the statutory federal rate as a result of percentage depletion in excess of basis and the tax effects of stock-based compensation, partially offset by state income taxes net of the federal benefit. Our quarterly income tax provisions are based on our reasonable estimates of income taxes payable at the end of the year. These estimates and our estimated interim effective tax rates may change significantly as additional financial results and amounts of capital spending become available during the year. In particular, our estimates of the utilization of excess percentage depletion, which is limited to 65% of actual taxable income, are subject to greater fluctuations between interim periods than other components of our tax provision.

There were neither unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during any periods presented in the financial statements. We believe we have appropriate support for the income tax positions taken and to be taken on our tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of various 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 years ended June 30, 2014 through June 30, 2017 for federal tax purposes and for the years ended June 30, 2013 through June 30, 2017 for state tax purposes. To the extent we utilize net operating losses generated in earlier years, such earlier years may also be subject to audit.

~~Table of Contents~~

~~Evolution Petroleum Corporation And Subsidiaries~~

~~Notes to Unaudited Consolidated Condensed Financial Statements~~

~~Note 12 —Net Income Per~~11. Earnings (Loss) per Common Share

The following table sets forth the computation of basic and diluted ~~income~~earnings (loss) per ~~share:~~

~~Outstanding potentially dilutive securities as~~common share, reflecting the application of ~~December 31, 2017 were as follows:~~

~~Outstanding potentially dilutive securities as of December 31, 2016 were as follows:~~

~~Note 13 — Senior Secured Credit Agreement~~

~~On April 11, 2016,~~ the Company entered into a three-year, senior secured reserve-based credit facility ("Facility") in an amount up to $50 million. The Facility replaces the Company's previous unsecured credit facility which expired in April 2016. The borrowing base under the Facility has been set at $10two-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 ~~was subsequently increased to $40~~0.1 million ~~effective February 1, 2018. As of December 31, 2017, the Company was in compliance with all covenants contained in the Facility, and no amounts were outstanding under the Facility.~~

Borrowings from the Facility may be used for the acquisition and development of oil and gas properties and for letters of credit and other general corporate purposes. Availability of borrowings under the Facility is subject to semi-annual borrowing base redeterminations.

The Facility included a placement fee of 0.50% on the initial borrowing base, amounting to $50,000, and carries a commitment fee of 0.25% per annum on the undrawn portion of the borrowing base. Any borrowings under the Facility will bear interest, at the Company’s option, at either LIBOR plus 2.75% or the Prime Rate, as defined, plus 1.00%. The Facility contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (a) a maximum total leverage ratio of not more than 3.00 to 1.00, (b) a debt service coverage ratio of not less than 1.10 to 1.00, and (c) a consolidated tangible net worth of not less than $40 million, all as defined under the Facility.

~~Table of Contents~~

~~Evolution Petroleum Corporation And Subsidiaries~~

~~Notes to Unaudited Consolidated Condensed Financial Statements~~

In connection with this agreement, the Company incurred $168,972 of debt issuance costs. Such costs were capitalized in Other Assets and are being amortized to expense. The unamortized balance in debt issuance costs related to the Facility was $70,334 as of December 31, 2017.

~~Note 14 — Commitments and Contingencies~~

We are subject to various claims and contingencies in the normal course of business. In addition, from time to time, we receive communications from government or regulatory agencies concerning investigations or allegations of noncompliance with laws or regulations in jurisdictions in which we operate. At a minimum we disclose such matters if we believe it is reasonably possible that a future event or events will confirm a loss through impairment of an asset or the incurrence of a liability. We accrue a loss if we believe it is probable that a future event or events will confirm a loss and we can reasonably estimate such loss and we do not accrue future legal costs related to that loss. Furthermore, we will disclose any matter that is unasserted if we consider it probable that a claim will be asserted and there is a reasonable possibility that the outcome will be unfavorable. We expense legal defense costs as they are incurred.

On December 3, 2013, our wholly owned subsidiary, NGS Sub Corp., was served with a lawsuit filed in the 8th Judicial District Court of Winn Parish, Louisiana by Cecil M. Brooks and Brandon Hawkins, residents of Louisiana, alleging that in 2006 a former subsidiary of NGS Sub Corp. improperly disposed of water from an off-lease well into a well located on the plaintiffs’ lands in Winn Parish. The plaintiffs requested monetary damages and other relief. The plaintiffs subsequently filed an amended petition joining the Company as defendants in its capacity as parent company of NGS Sub Corp. NGS Sub Corp. divested its ownership of the property in question along with its ownership of the subsidiary in 2008 to a third party. NGS Sub Corp. and the Company have denied the plaintiffs’ claims. The district court dismissed the claim of Mr. Brooks against NGS Sub Corp. and the Company because Mr. Brooks purchased the land where the well is located subsequent to the divestiture of the property by NGS Sub Corp. The claim of Mr. Hawkins is still being defended. A bench trial is currently scheduled for March 2018. We will continue to vigorously defend the claims and based on the input of our legal counsel, we consider the likelihood of a loss in this matter that is material to the financial position of the Company to be remote.

~~Rent expense~~ for the three ~~months ended December 31, 2017~~ and ~~2016 was $19,198 and $18,569, respectively. Rent expense for the~~ six months ended December 31, ~~2017~~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 ~~2016 was $39,049~~performance-based), totaling approximately 90,000 and ~~$53,425, respectively.~~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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EVOLUTION PETROLEUM CORPORATION

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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EVOLUTION PETROLEUM CORPORATION

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

~~The following discussion~~

Executive Overview

Liquidity and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and in our Annual Report on Form 10-K for the year ended June 30, 2017 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Capital Resources

Results of Operations contained in the Form 10‑K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K. Certain dollar amounts and percentages in this Management’s Discussion and Analysis of Financial Condition and Results of Operations and other parts of this Quarterly Report on Form 10-Q have been rounded for presentation, and certain amounts may not sum due to rounding.

~~We use the terms, “EPM,” “Company,” “we,” “us” and “our” to refer to Evolution Petroleum Corporation and its wholly owned subsidiaries.~~

~~Executive Overview~~

~~General~~

We are engaged primarily in the development and production of oil and gas reserves within known oil and gas resources utilizing conventional technology with a focus on creating value on a per share basis. In doing so, we depend on a capital structure with low or no leverage, allowing us to maintain control of our assets for the benefit of our stockholders. By policy, every employee and director maintains a beneficial ownership position in our common stock. We believe this ownership helps ensure that the interests of our employees and directors are aligned with our shareholders.

~~Our strategy is to maximize the value realized by our stockholders from our assets, particularly our core Delhi asset.~~

~~Highlights for our Second Quarter of Fiscal 2018 and Operations Update~~

Critical Accounting Policies

Commonly Used Terms

“Current ~~quarter"~~quarter” refers to the three months ended December 31, ~~2017, the Company's second quarter of fiscal 2018.~~

~~"Prior quarter" refers to the three months ended September 30, 2017, the Company's~~2023, our first quarter of fiscal ~~2018.~~

"year 2024.

“Year-ago ~~quarter"~~quarter” refers to the three months ended December 31, ~~2016, the Company's second~~2022, our first quarter of fiscal ~~2017.~~

~~Highlights for~~year 2023.

Executive Overview

General

Evolution Petroleum Corporation is an independent energy company focused on maximizing total returns to its shareholders through the ~~Quarter:~~

~~We reported revenues~~ownership of ~~$11.1 million for~~and investment in onshore oil and natural gas properties in the ~~current quarter,~~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 ~~increase~~established operator in the geographic region.

Our non-operated interests in the Williston Basin, an oil and natural gas producing property, consist of ~~30% over both~~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 ~~prior~~geographic region.

Our non-operated interests in the Barnett Shale, a natural gas and ~~year-ago quarters.~~

~~Current quarter~~NGL producing shale reservoir, consist of approximately 17% average net ~~income was $9.9 million, or $0.30 per common share, compared~~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 ~~income~~working interest, with an associated 20% average net revenue interest (inclusive of ~~$0.07 per common share in both~~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 ~~prior and year-ago quarters.~~

~~Net income for the current quarter included a one-time $6.0 million non-cash tax benefit related to passage~~majority of the ~~Tax Cuts and Jobs Act~~

Table of ~~2017.~~Contents

~~Our realized oil price for the current quarter was $57.30 per barrel, the highest quarterly average since the quarter ended June 30, 2015.~~

~~We paid our seventeenth consecutive quarterly cash dividend on common shares,~~

remaining working interest in the ~~amount of $0.075 per share, and announced an increase~~Hamilton Dome Field. The Hamilton Dome Field is located in the ~~quarterly dividend rate to $0.10 per share for~~southwest region of the ~~quarter ending March 31, 2018.~~

~~We ended the current quarter with $27.6 million of working capital, an increase of $3.2 million from the prior quarter, after paying $2.5 million~~Big Horn Basin in ~~common stock dividends.~~

~~Projects~~

Additional property and project information is included under Item 1. Business, Item 2. Properties, Notes to the Financial Statements and Exhibit 99.4 of our Form 10-K for the year ended June 30, 2017.

~~Delhi Field - Enhanced Oil Recovery Project~~

northwest Wyoming.

Our non-operated interests in the Delhi ~~field~~Field, a CO₂-EOR project producing oil and NGLs, consist of ~~a 23.9%~~approximately 24% average net working interest, ~~(with~~with an associated ~~19.0% net~~19% revenue ~~interest)~~interest and separate overriding royalty and mineral interests of ~~7.2%. This yields~~approximately 7% yielding a total average net revenue interest of ~~26.2%~~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

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.

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.

Appointment of Chief Accounting Officer

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

Share Repurchase Program

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

~~Gross~~

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Chaveroo Oilfield Participation Agreement

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

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

During the three months ended September 30, 2023, we paid total cash consideration of $0.4 million, which includes less than $0.1 million of capitalized transaction costs, in exchange for a 50% working interest share in 1,625 gross 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.

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 ~~production at Delhi in~~prices falling to historic lows during the second quarter of ~~fiscal 2018 averaged 7,370 barrels~~2020 and remaining depressed through much of 2020. Beginning in 2021, the demand for oil ~~per day ("BOPD"), or 1,932 BOPD net to our interests, a 6.6% increase from the prior quarter~~ and a 2.8% decrease from the year-ago quarter. Oil production in the quarter increased as we put additional existing compression capacity in service and experimented with larger choke sizes to boost the injection of CO₂. We also had very few days of scheduled and unscheduled facility downtime compared to the prior quarter. Lastly, we benefited from lower air temperatures, after the high heat of the summer adversely effected production levels.

~~Gross~~ natural gas ~~liquid ("NGL") sales for this quarter of production were 1,079 barrels of oil equivalent per day ("BOEPD"), or 283 BOEPD net~~started to ~~our interests, up slightly from 1,047~~ BOEPD in the prior quarter. NGL production rates in the prior quarter were impacted by both planned and unplanned downtime in the field and at the central production facilities. In early August, the plant was shut-in for four days to perform capital upgrades to the inlet of the recycle facility. ~~Results from the NGL plant subsequent to completion of this project have been positive, with the plant operating at or near maximum capacity and efficiency.~~ ~~The NGL plant is accomplishing its primary objective of removing the lighter hydrocarbons (i.e. methane and ethane) to increase the purity of the CO~~₂ recycle stream and improve the efficiency of the flood. Over time, this is expected to increase the recovery of crude oil in the field. The plant is also producing significant quantities of higher value NGL's for sale as well as providing methane and ethane feedstock to power the electric turbine.

Production from the NGL plant is transported by truck to a processing plant in East Texas. Under our current marketing contract, we receive market index pricing for each NGL component, based on the processed yield, less transportation and processing fees. There may also be an adjustment for NGL's that do not meet the purchaser's required specifications. The current mix of products contains a large percentage (over 65%) of higher value NGL's, such as pentanes and butane, and almost no lower value ethane. Market pricing for our NGL's during the past two quarters has been favorable, with net realized NGL prices averaging approximately 60% of WTI prices. NGL demand often has a seasonal pattern and prices tend to be higher during the cooler months of October through March.

During the extreme cold of January 2018, we experienced two weather-related disruptions to production in the field, including an extended outage at the NGL plant. These issues have been remedied and the field and NGL plant are producing at normal capacity.

Field operating expenses were $14.30 per barrel of oil equivalent ("BOE") in the current quarter compared to $15.06 in the prior quarter. Our total lease operating expenses in the Delhi field were $2.9 million in the current quarter, essentially unchanged from the prior quarter, and $0.6 million over the year-ago quarter. Our purchased CO₂ ~~costs increased to $1.3 million ($6.21 per BOE) from $1.1 million ($5.67 per BOE) in the prior quarter. Purchased CO~~₂ ~~volumes were approximately the same in the two periods, but our costs per Mcf increased~~recover primarily as a result of ~~higher realized oil prices~~the roll-out of the COVID-19 vaccine and lessening of pandemic related government restrictions on individuals and businesses.

In addition, the conflict in the ~~field,~~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 ~~are directly tied to the price per Mcf for purchased CO~~₂~~. Under our contract with the operator, purchased CO~~₂ ~~is priced at 1%~~have further enhanced volatility in global commodity prices.

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

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

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

Currently, our oil ~~price in~~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 ~~field per thousand cubic feet (“Mcf”) plus sales taxes~~operation or future development of 8%such properties. Despite these uncertainties, we remain focused on our long-term objectives and ~~transportation costs~~continue to be proactive with our third-party operators to review capital expenditures and present alternative plans as necessary.

Table of ~~$0.20 per Mcf. Our other lease operating costs were $1.6 million, down from $1.8~~Contents

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 ~~the prior quarter.~~

~~2017 Tax Cuts~~cash and ~~Jobs Act~~

~~On December 22, 2017, the U.S. government enacted comprehensive tax legislation under the title of the Tax Cuts~~cash equivalents compared to $11.0 million in cash and Jobs Act ("Tax Act"). The Tax Act includes a permanent reduction in our federal corporate income tax rate from 34% to 21%. It also provides more favorable tax deductions associated with capital investments and other significant changes to tax law. The Tax Act became effective upon passage, so our statutory rate for the current fiscal year endedcash equivalents at June 30, ~~2018 is a blended rate~~2023. Our primary sources of ~~27.55%. The permanent reduction in~~liquidity and capital resources during the federal corporate income tax rate resulted in a one-time non-cash income tax benefit of approximately $6.0 million related to the adjustment of our liability for deferred income taxes to the lower rate in the Tax Act. The accounting for the effects of the rate change on the Company’s deferred tax balances is complete and no provisional amounts were recorded.

Three Months Ended
December 31, Six Months Ended
December 31,
2017 2016 2017 2016
Income before income taxes 4,824,637
3,668,731
7,355,491
6,374,682
Income tax (benefit) provision (a) (5,052,211 ) 1,361,097
(4,661,889 ) 2,250,273
Effective tax rate (a) (105 )% 37 % (63 )% 35 %

~~(a) The income tax provision for the three months and~~ six months ended December 31, ~~2017 includes a one-time non-cash benefit of approximately $6.0 million for~~2023 were cash provided by operations and the ~~adjustment~~unused portion of our ~~liability for deferred income taxes to the lower rate in the Tax Act. This adjustment results in a negative effective tax rate (benefit) for these periods.~~

~~Income taxes are recorded in our financial statements based on our estimated annual effective income tax rate. The effective rates used in the calculation~~Senior Secured Credit Facility. Our primary uses of ~~our income tax expense were approximately 21%~~liquidity and ~~37%~~capital resources for the three months ended December 31, ~~2017~~2023 were cash dividend payments to our common stockholders, capital expenditures on our existing oil and ~~2016, respectively. Including~~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 ~~adjustment for~~lender based on the ~~$6.0 million discrete benefit resulting from the revaluation~~value of our ~~deferred income tax liabilities,~~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 ~~effective rate for~~SOFR plus 2.80% or the ~~quarter ended December 31, 2017 was a tax benefit of (105)% of income before income taxes.~~

~~For~~Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%. During the six months ended December 31, ~~2017 and 2016 the effective rates used in the calculation of~~2023, we did not have any borrowings outstanding under our income tax expense were approximately 20% and 35% , respectively. Including the adjustment for the $6.0 million discrete benefit resulting from the revaluation of our deferred income tax liabilities, the effective rate for the six months ended December 31, 2017 was a tax benefit of (63)% of income before income taxes.

Excluding the impact of the $6.0 million deferred tax adjustment, the effective tax rates for the three months and six months ended December 31, 2017 were lower than the corresponding prior periods as a result of the lower statutory tax rate and higher utilization of percentage depletion in excess of basis during the current year.

~~Liquidity and Capital Resources~~

~~We had $25.7 million and $23.0 million in cash and cash equivalents at December 31, 2017 and June 30, 2017, respectively.~~

~~In addition, we have a senior secured reserve-based credit facility (the "Facility") with a maximum capacity of $50.0 million.~~Senior Secured Credit Facility. The Facility had $10.0 million of borrowing base availability on December 31, 2017 and June 30, 2017, respectively. Effective February 1, 2018, the borrowing base and availability under the Facility was expanded to $40.0 million. There have been no borrowings under the Facility, which matures on April 11, 2019 and is secured by substantially all of the Company’s assets.

~~Any future borrowings bear interest, at the Company's option, at either LIBOR plus 2.75% or the Prime Rate, as defined, plus 1.0%. The~~Senior Secured Credit Facility contains covenants ~~that require~~requiring the maintenance of (i) a total leverage ratio of not more than ~~3.0~~3.00 to ~~1.0,~~1.00, (ii) a ~~debt service coverage~~current ratio of not less than ~~1.1~~1.00 to ~~1.0~~1.00, and (iii) a consolidated tangible net worth of not less than ~~$40~~$40.0 million, each as defined in the Senior Secured Credit Facility. ~~The Facility~~It also contains other customary affirmative and negative covenants, including a hedging covenant discussed below, and events of default. As of December 31, ~~2017, the Company was~~2023, we were in compliance with all covenants ~~contained~~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 ~~Facility.~~

~~During~~Ninth Amendment to the ~~six months ended December 31, 2017, we funded~~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 ~~operations~~Margined Collateral Value takes into account the estimated value of our oil and ~~cash dividends~~natural gas properties, proved developed reserves, total indebtedness, and other relevant factors consistent with ~~cash generated from operations~~customary oil and natural gas lending criteria. We expect to be subject to these hedge requirements upon the closing of our cash balance increased $2.7 million during that period. As of December 31, 2017, our working capital was $27.6 million, an increase of $4.2 million over working capital of $23.4 million at June 30, 2017.

pending SCOOP/STACK Acquisitions.

We have historically funded ~~our~~ operations through cash from operations and working ~~capital.~~capital and utilized our credit facility for property acquisitions. Our primary source of cash from operations is the sale of produced crude oil, ~~and~~ natural gas, ~~liquids production.~~and NGLs. A portion of these cash flows ~~are~~is used to fund ~~our~~ capital ~~expenditures. While we~~expenditures and pay cash dividends to shareholders. We expect to ~~continue to expend~~fund near-future capital ~~to further develop the Delhi field, we and the operator have flexibility as to when this capital is spent. The Company expects to manage future development~~expenditures with cash flows from operating activities ~~in the Delhi field within the boundaries of its operating cash flow~~ and existing working ~~capital.~~

capital, and as needed from borrowings under our Senior Secured Credit Facility.

We ~~may choose to evaluate and pursue~~are pursuing new growth opportunities through acquisitions orand other transactions. WeIn addition to cash on hand, we have access to ~~at least $40 million~~the undrawn portion of ~~availability~~the borrowing base available under our ~~senior secured credit facility if required. In addition we~~Senior Secured Credit Facility, totaling $50.0 million as of December 31, 2023. We also have an effective shelf registration statement with ~~Securities and Exchange Commission~~the SEC under which we may issue up to $500.0 million of new debt or equity securities. If we choose to pursue new growth opportunities, we would expect to use our internal resources of cash, working capital and borrowing capacity under our credit facility. It may also be advantageous for us to consider issuing additional equity as part of any potential transaction, but we have no specific plans to do so at this time.

Our ~~other significant use of cash is our on-going dividend program. The~~ Board of Directors instituted a cash dividend on ~~our~~ common stock in December ~~2013 and we~~2013. We have since paid ~~seventeen~~41 consecutive quarterly dividends. Distribution of a substantial portion of free cash flow in excess of ~~our~~ operating and capital requirements through cash dividends ~~and potential repurchases of our common stock~~ remains a priority of our financial strategy, and it is our ~~long term~~long-term goal to increase ~~our~~ dividends over time, as appropriate. InOn February ~~2018,~~5, 2024, the Board of Directors declared ~~an increase~~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 ~~quarterly common stock dividend~~open market through December 31, 2024. We intend to fund any repurchases from ~~$0.075 per share~~working capital and cash provided by operating activities. As we continue to ~~$0.10 per share, effective~~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 ~~payment~~policy and investment opportunities, and is a tax efficient means to further improve shareholder return.

In November 2023, we entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in ~~March 2018.~~the open market subject to pre-defined limitations on trading volume and price. The ~~Board reviews~~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 ~~quarterly dividend rate in light~~terms of the plan from time to time to the extent we determine changes are necessary to achieve the intended objectives of our ~~financial position and operations, forecasted results, including the outlook for oil and NGL prices, the timing of further expansion of Delhi development and other potential growth opportunities.~~

repurchase program.

Capital ~~Budget - Delhi Field~~

Expenditures

During the six months ended December 31, ~~2017,~~2023, we incurred ~~$1.4~~$5.7 million ~~of capital expenditures at Delhi. This spending included $0.4 million for capital upgrades to the recycle plant, $0.5 million for Phase V infrastructure, $0.4 million for CO~~₂ ~~conformance projects and $0.1 million for other~~in capital expenditures.

~~A twelve-well infill~~ During the current quarter, we participated in the drilling ~~program~~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 has been approved and is planned to commence during the quarter ended March 31, 2018. The infill program has a revised estimated net cost of $4.7 million, the majority of which~~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 ~~incurred~~ in the ~~remainder~~range of ~~the current fiscal year. The program consists of five new CO~~₂ ~~injection wells and seven new production wells and targets productive oil zones~~$10.0 million to $14.0 million, which ~~we believe are not being swept effectively by the current CO~~₂ ~~flood. It is~~excludes any potential acquisitions. Our expected ~~to both add production and increase ultimate recoveries above the current developed producing oil reserves. The operator estimates it will take up to five months to drill and complete all the wells.~~

~~We have also approved additional net~~ capital expenditures for fiscal ~~2018 totaling $2.8 million for water injection, flowlines~~year 2024 include the two new drilled wells at Delhi Field and ~~other infrastructure projects~~three wells at Chaveroo Field, both of which are discussed above. We also expect to start incurring capital expenditures, in ~~preparation~~the fourth quarter at Chaveroo Field, for the ~~Phase V pattern development. Approximately $0.5~~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, ~~of these costs have been incurred as of December 31, 2017. In addition, we expect to continue to perform conformance workover~~before customary closing adjustments. Our budgeted capital expenditures discussed above do not include any potential capital projects ~~and will likely incur additional maintenance capital expenditures. Such amounts cannot be estimated accurately at this time, but are not expected to be material to our financial position.~~

associated with properties in the SCOOP/STACK Acquisitions.

Funding for our anticipated capital expenditures ~~at Delhi~~ over the ~~next fiscal year~~near-term is expected to be met from cash flows from operations and current working ~~capital.~~

~~Overview of Cash Flow Activities~~

~~Net cash provided by operating activities~~capital and, as needed, from operations was $9.1 million and $5.9 million for the six months ended December 31, 2017 and 2016, respectively. The $3.2 million increase in cash provided by operations between these two periods resulted from $7.9 million of higher net income and a $1.2 million increase in cash provided by operating assets and liabilities, partially offset by a $5.9 million decrease in non-cash expenses and other adjustments to reconcile net income to net cash provided by operations. This decrease includes a $6.0 million one-time adjustment ofborrowings under our ~~deferred income tax liability to the lower corporate tax rate under the 2017 Tax Cuts and Jobs Act.~~

Net cash used in investing activities was $1.0 million and $8.3 million for the six months ended December 31, 2017 and 2016, respectively. The decrease in cash outflows was primarily due to $7.0 million of lower capital expenditures together with a $0.3 million decline in derivative settlement payments.

Net cash used by financing activities for the six months ended December 31, 2017 and 2016 was $5.4 million and $12.4 million, respectively. The $7.1 million decrease in cash used was principally due to $7.9 million disbursed in the prior fiscal to redeem our preferred stock, $0.3 million of pre-redemption preferred dividend payments, and a $0.1 million decline in treasury stock purchases, partially offset by an increase of $1.2 million in common share dividends paid as a result of increases in dividend rates per share.

Senior Secured Credit Facility.

Full Cost Pool Ceiling Test ~~and Proved Undeveloped Reserves~~

As of December 31, 2017, our capitalized costs of oil and gas properties were substantially below the full cost valuation ceiling. We do not currently expect that a write-down of capitalized oil and gas property costs will be required in the remaining quarters of fiscal 2018. However, persistent and substantially lower oil prices would have an effect on the excess, or cushion, of our valuation ceiling over our capitalized costs in the current quarter and could adversely impact our ceiling tests in future quarters.

Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated ~~DD&A~~depletion, depreciation, and amortization and related deferred taxes, are limited to ~~(the full cost valuation “ceiling”):~~ the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%~~; plus the cost of any properties not being amortized;~~, plus the lower of cost or fair value of unproved properties, ~~included in costs being amortized; less the~~as adjusted for related income tax ~~effect related to the differences between the book and tax basis of the properties.~~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 ~~received~~ for our petroleum products during the ~~twelve month~~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 ~~prices drop below the average~~price levels were to substantially decline from the ~~past twelve months,~~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 ~~ceiling test calculations would be adversely affected.~~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.

Table of Contents

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

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 ~~proved undeveloped reserves at June 30, 2017 included 544 MBOE~~average realized price per barrel of ~~reserves and $3.2~~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 ~~of future development costs associated with a planned infill drilling program and 1,564 MBOE of reserves and $10.9 million of future development costs associated with~~compared to the ~~Phase V development in the eastern portion of the field. The objective of the infill drilling program is~~six months ended December 31, 2022 due to ~~increase production and recover reserves which are not believed to be effectively producible with the existing well configuration. The project includes both acceleration of production and~~ an increase in ~~ultimate reserve recovery and has been recorded as a proved undeveloped project. The infill project, which was increased from eight wells to twelve wells subsequent~~capital expenditures related to the ~~date~~drilling and completion of ~~the reserve report, is expected to begin~~three new wells in the ~~third quarter~~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 ~~fiscal 2018. The timing~~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.

Table of ~~our Phase V development is dependent in part on the results and CO~~₂ ~~requirement~~Contents

Results of ~~the infill program. At present, we expect to begin this development in calendar 2019.~~

Operations

Three Months Ended December 31, ~~2017~~2023 and ~~2016~~

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 ~~sets forth certain~~summarizes the comparison of financial information for the periods presented:


	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)	%

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)	%

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.

Table of Contents

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 ~~respect~~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.

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 ~~operations:~~prices as well as decreased production volumes described above as production taxes are based on sales at the wellhead.

The following table summarizes CO₂costs per Mcf and CO₂volumes for the 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.


	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)	%

The $0.4 million decrease in CO₂costs for the three months ended December 31, 2023 was primarily due to a 15.8% decrease in purchased CO₂volumes combined with a 4.0% decrease in CO₂ costs per MCF, which was driven by a decrease in our average realized oil price. 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 CO₂pipeline 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.

Table of Contents

Three Months Ended December 31,
2017 2016 Variance Variance %
Oil and gas production:
  Crude oil revenues $ 10,185,635
$ 8,529,817
$ 1,655,818
19.4 %
  NGL revenues 881,276
—
881,276
n.m.
  Total revenues $ 11,066,911
$ 8,529,817
$ 2,537,094
29.7 %

  Crude oil volumes (Bbl) 177,767
182,815
(5,048 ) (2.8 )%
  NGL volumes (Bbl) 26,033
—
26,033
n.m.
Equivalent volumes (BOE) 203,800
182,815
20,985
11.5 %

  Crude oil (BOPD, net) 1,932
1,987
(55 ) (2.8 )%
  NGLs (BOEPD, net) 283
—
283
n.m.
Equivalent volumes (BOEPD, net) 2,215
1,987
228
11.5 %

  Crude oil price per Bbl $ 57.30
$ 46.66
$ 10.64
22.8 %
  NGL price per Bbl 33.85
—
33.85
n.m.
    Equivalent price per BOE $ 54.30
$ 46.66
$ 7.64
16.4 %

CO₂ costs
$ 1,265,582
$ 1,041,741
$ 223,841
21.5 %
All other lease operating expenses 1,648,930
1,250,680
398,250
31.8 %
  Production costs $ 2,914,512
$ 2,292,421
$ 622,091
27.1 %
  Production costs per BOE $ 14.30
$ 12.54
$ 1.76
14.0 %
CO₂ volumes (MMcf per day, gross)
69.7
67.0
2.7
4.0 %

Oil and gas DD&A (a) $ 1,626,324
$ 1,299,813
$ 326,511
25.1 %
Oil and gas DD&A per BOE $ 7.98
$ 7.11
$ 0.87
12.2 %

~~n.m. Not meaningful.~~

~~(a) Excludes $7,544~~

Depletion of Full Cost Proved Oil and ~~$7,697~~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 ~~other depreciation~~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 ~~amortization~~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, ~~2017 and 2016, respectively.~~

~~Net Income Available~~2023 increased $0.1 million to ~~Common Stockholders.~~ ~~During the three months ended December 31, 2017, we generated net income of $9.9~~$0.6 million ~~or $0.30 per diluted share, on total revenues of $11.1 million. This compares~~compared to ~~net income of $2.3~~$0.5 million or $0.07 per diluted share, on revenues of $8.5 million for the year-ago quarter. The $7.6 million earnings increase reflects a $2.5 million revenue increase, a $6.4 million decline in income taxes primarily attributable to the impact of the 2017 Tax Cuts and Jobs Act, partially offset by $1.4 million of higher operating expenses.

~~Oil and Gas Revenues.~~ ~~Revenues increased 30% to $11.1 million as a result of a~~ ~~11.5%~~ increase in production volumes from the year-ago quarter, together with a 16% increase in realized oil and NGL prices from $46.66 per equivalent barrel to $54.30 per equivalent barrel in the current quarter. All of our revenues for the current and year-ago quarters came from the Delhi field. Net Delhi oil production volumes of 1,932 BOPD decreased 55 BOPD from the year-ago quarter, as a number of highly successful conformance and production enhancement operations in the prior year ~~stabilized at lower rates~~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 ~~current quarter. Net NGL production averaged 283 BOEPD~~mark-to-market valuation of the derivative contracts in the ~~current quarter, at an~~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 ~~sales price~~realized prices for the periods presented. As of ~~$33.85 per barrel. There~~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 ~~no NGL sales~~required by terms set in the ~~year-ago quarter as NGL plant production began~~Senior Secured Credit Facility to hedge a portion of our production. The increase in ~~January 2017.~~

~~Production Costs. Production costs~~commodity prices since entering into those hedges resulted in realized losses on derivative contracts for the ~~current quarter were $2.9 million, a $0.6 million, or 27%, increase from the year-ago quarter, primarily due to to higher CO~~₂ ~~costs and the incremental operating costs~~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)	%

Table of ~~the NGL plant that commenced operations in January 2017. CO~~₂ costs increased $0.2 million, or 21%, due to a higher purchase cost per Mcf, which is derived from the realized field oil price, together with 4% increase in purchase volumes. Average gross purchased CO₂ volumes increased from 67.0 MMcf per day in the year-ago quarter to 69.7 MMcf per day for the current quarter. Other production costs, which include incremental costs of the NGL plant, power, chemicals, repairs and maintenance, labor and overhead, increased $0.4 million, or 32%, from the year-ago quarter. Virtually all of this increase was attributable to the NGL plant. Production costs per equivalent barrel in the current quarter were $14.30 per BOE on total production volumes, compared to $15.06 per BOE in the year-ago quarter.Contents

~~Calculated solely on our Delhi working interest volumes, production costs were $18.75 per BOE, of which $8.55 per BOE was CO~~₂cost. These costs per equivalent barrel exclude production volumes from our royalty interests in the Delhi field, which bear almost no production costs, and are therefore higher than the rates per barrel on our total production volumes.

~~General and Administrative Expenses (“G&A”).~~ ~~G&A expenses increased $0.4 million, or 34%, to $1.7~~

Interest Expense

Interest expense decreased $0.1 million for the three months ended December 31, ~~2017 as a result~~2023 compared to the prior year period primarily due to repayments of ~~$0.2~~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 ~~higher non-cash stock compensation~~$1.6 million compared to income tax expense ~~$0.1~~of $2.9 million ~~for litigation costs and $0.1 million for due diligence costs associated with property evaluations.~~

~~Depreciation, Depletion & Amortization Expense (“DD&A”).~~ ~~DD&A increased $0.3 million, or 25%, to $1.6~~on net income before income taxes of $13.3 million for the ~~current quarter~~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 ~~year-ago~~prior year period ~~primarily~~ as projected state income taxes have become a ~~result~~larger component of ~~higher full cost amortization, reflecting an 11% increase in production to 203,800 BOE, together with a 12% higher amortization rate~~our overall income tax expense during the period.

Table of ~~$7.98 per BOE. The higher rate is principally due to increased development costs.~~Contents

Six Months Ended December 31, ~~2017~~2023 and ~~2016~~

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 ~~sets forth certain~~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 ~~respect~~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 ~~operations:~~prices as well as decreased production volumes described above as production taxes are based on sales at the wellhead.

The following table summarizes CO₂costs per Mcf and CO₂volumes for the 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 CO₂costs for the six months ended December 31, 2023 was primarily due to a 17.7% decrease in purchased CO₂volumes 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.

Six Months Ended December 31,
2017 2016 Variance Variance %
Oil and gas production:
  Crude oil revenues $ 18,014,890
$ 16,123,672
$ 1,891,218
11.7 %
  NGL revenues 1,589,892
89
1,589,803
n.m.
  Natural gas revenues —
(4 ) 4
n.m.
  Total revenues $ 19,604,782
$ 16,123,757
$ 3,481,025
21.6 %

  Crude oil volumes (Bbl) 344,504
360,817
(16,313 ) (4.5 )%
  NGL volumes (Bbl) 51,279
4
51,275
n.m.
  Natural gas volumes (Mcf) —
16
(16 ) n.m.
Equivalent volumes (BOE) 395,783
360,824
34,959
9.7 %

  Crude oil (BOPD, net) 1,872
1,961
(89 ) (4.5 )%
  NGLs (BOEPD, net) 279
—
279
n.m.
  Natural gas (BOEPD, net) —
—
—
n.m.
Equivalent volumes (BOEPD, net) 2,151
1,961
190
9.7 %

  Crude oil price per Bbl $ 52.29
$ 44.69
$ 7.60
17.0 %
  NGL price per Bbl 31.00
22.25
8.75
39.3 %
  Natural gas price per Mcf —
(0.25 ) 0.25
n.m.
    Equivalent price per BOE $ 49.53
$ 44.69
$ 4.84
10.8 %

CO₂ costs
$ 2,353,843
$ 2,119,874
$ 233,969
11.0 %
All other lease operating expenses 3,452,255
2,517,188
935,067
37.1 %
  Production costs $ 5,806,098
$ 4,637,062
$ 1,169,036
25.2 %
  Production costs per BOE $ 14.67
$ 12.85
$ 1.82
14.2 %

CO₂ volumes (MMcf per day, gross)
69.5
70.4
(0.9 ) (1.3 )%

Oil and gas DD&A (a) $ 3,137,205
$ 2,565,450
$ 571,755
22.3 %
Oil and gas DD&A per BOE $ 7.93
$ 7.11
$ 0.82
11.5 %

~~n.m. Not meaningful.~~

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Net ~~Income Available~~Gain (Loss) on Derivative Contracts

Periodically, we utilize commodity derivative financial instruments to ~~Common Stockholders.~~ ~~During~~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 ~~six months ended~~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, ~~2017,~~2023, we ~~generated net income~~did not have any open crude oil or natural gas derivative contracts. In the prior year period, because of ~~$12.0 million, or $0.36 per diluted share,~~our acquisitions during fiscal year 2022 and the corresponding borrowings on ~~total revenues~~our Senior Secured Credit Facility, we were required by terms set in the Senior Secured Credit Facility to hedge a portion of ~~$19.6 million. This compares to net income of $2.9 million, or $0.09 per diluted share,~~our production. The increase in commodity prices since entering into those hedges resulted in realized losses on ~~revenues of $16.1~~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, ~~2016. The $9.1 million earnings increase reflects higher revenues of $3.5 million, an income tax decrease of $6.9 million primarily attributable~~2023 compared to the impact of Tax Cuts and Jobs Act, and a $1.2 million decrease in allocated net income to holders of preferred shares retired in November 2016, partially offset by $2.5 million of higher operating expenses.

~~Oil and Gas Revenues.~~ ~~Revenues increased 22% to $19.6 million as a result of a~~ ~~10%~~ ~~increase in production volumes over~~ the prior year period together with a 11% increase in realized prices from $44.69 per equivalent barrel to $49.53 per equivalent barrel. All of our revenues in the current fiscal year came from the Delhi field, as well as virtually all of our revenues from the prior year. Net Delhi oil production volumes of 1,872 BOPD decreased 89 BOPD from the prior year period. Net NGL production averaged 279 BOEPD, at an average price of $31.00 per barrel. There were no NGL sales in the year-ago period as NGL plant production began in January 2017.

~~Production Costs. Production costs for the current year period were $5.8 million, a $1.2 million, or 25%, increase from the same period a year ago,~~ primarily due to ~~higher CO~~₂ ~~costs and~~repayments of borrowings outstanding on our Senior Secured Credit Facility during the ~~incremental operating costs~~prior fiscal year.

Income Tax (Expense) Benefit

For the six months ended December 31, 2023, we recognized income tax expense of ~~the NGL plant that commenced operations in January 2017. CO~~₂ ~~costs increased $0.2~~$1.0 million ~~or 11%, due to higher purchase cost per Mcf, which is derived from the realized field oil price, partially offset by a slight 1% decline in purchase volumes. Average gross purchased CO~~₂ ~~volumes decreased from 70.4 MMcf per day in the year-ago period to 69.5 MMcf per day for the current year. Other production costs, which include incremental costs~~on net income before income taxes of ~~the NGL plant, power, chemicals, repairs and maintenance, labor and overhead, increased $0.9~~$3.6 million or 37%, from the year-ago period. Virtually all of this increase was attributable to the NGL plant. Production costs per equivalent barrel in the current period were $14.67 per BOE on total production volumes, compared to ~~$12.85 in the prior year period.~~

~~Calculated solely~~income tax expense of $6.0 million on ~~our Delhi working interest volumes, production costs were $19.24 per BOE,~~net income before income taxes of ~~which $8.19 per BOE was CO~~₂cost. These costs per equivalent barrel exclude production volumes from our royalty interests in the Delhi field, which bear almost no production costs, and are therefore higher than the rates per barrel on our total production volumes.

~~General and Administrative Expenses (“G&A”).~~ ~~G&A expenses increased $0.8 million, or 31%, to $3.2~~$27.1 million for the six months ended December 31, ~~2017.~~2022. The increase in expense included $0.4 million of non-cash stock-based compensation expense, $0.1 million of severance costs, $0.1 million of litigation expense, $0.1 million of due diligence costs associated with property evaluations,effective tax rates were 28.5% and ~~$0.1 million of higher board of director expenses.~~

~~Depreciation, Depletion & Amortization Expense (“DD&A”).~~ ~~DD&A~~22.1% for three months ended December 31, 2023 and 2022, respectively. The effective tax rate increased ~~$0.6 million, or 22%, to $3.2 million for the current period~~ compared to the ~~year-ago~~prior year period ~~primarily due to higher full cost amortization, reflecting~~as projected state income taxes have become a ~~10%~~ ~~increase~~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 ~~production to 395,783 BOE, together~~accordance with ~~a 12% higher amortization rate of $7.93 per BOE. The higher rate is principally due to increased development costs.~~

~~Other Economic Factors~~

~~Inflation. Although the general inflation rate~~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 ~~measured by~~of the ~~Consumer Price Index and~~date of the Producer Price Index, has been relatively low in recent years, the oil and gas industry has experienced unusually volatile price movements in commodity prices, vendor goods and oilfield services. Prices for drilling and oilfield services, oilfield equipment, tubulars, labor, expertise and other services impact our lease operating expenses and our capital expenditures. During fiscal 2018 to date, we have seen a firming of prices for operating and capital costs as a result of improving demand and a closer balance ~~with the supply of goods and services in the industry. Product prices, operating costs and development costs may not always move in tandem.~~

~~Known Trends and Uncertainties. General worldwide economic conditions,~~sheet as well as ~~economic conditions~~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

Table of Contents

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 oil and gas industry specifically, continue to be uncertain and volatile. Concerns over uncertain future economic growth are affecting numerous industries and companies, as well as consumers, which impact demand for crude oil and natural gas. If the supply of crude oil and natural gas exceeds demand in the future, it may put downward pressure on crude oil and natural gas prices, thereby lowering our revenues, profits, cash flow and working capital going forward. While we realized higher average oil prices in the quarter than any period since the quarterfiscal year ended June 30, ~~2015, there can be no assurance that such prices will continue to prevail or trend upward.~~

~~Seasonality~~. Our business is generally not directly seasonal, except for instances when weather conditions may adversely affect access to our properties or delivery of our petroleum products. Although we do not generally modify our production for changes in market demand, we do occasionally experience seasonality in the product prices we receive, driven by summer cooling and driving, winter heating, and extremes in seasonal weather, including hurricanes. We have also experienced adverse impacts on our production from very high summer temperatures and extremely cold winter weather.

~~Off Balance Sheet Arrangements~~

~~The Company had no off-balance sheet arrangements to report for the quarter ended December 31, 2017.~~

2023.

~~ITEM~~

Item 3. ~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS~~

~~Information about market~~ Quantitative and Qualitative Disclosures About Market Risks

Derivative Instruments and Hedging Activity

We are exposed to various risks, ~~for~~including energy commodity price risk, such as price differentials between the ~~three months ended December 31, 2017, did not change materially from~~NYMEX commodity price and the ~~disclosures in Item 7A of~~index price at the location where our ~~Annual Report on Form 10-K for the year ended June 30, 2017.~~

~~Commodity Price Risk~~

~~Our most significant market risk~~production is ~~the pricing for crude~~sold. When oil, natural gas, and ~~NGL's.~~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. If energy~~unpredictable, therefore we monitor commodity prices ~~decline significantly, our revenues and cash flow would significantly decline. In addition, a non-cash write-down~~to identify the potential need for the use of ~~our~~derivative financial instruments to provide partial protection against declines in oil and natural gas ~~properties could be required under full cost accounting rules if future oil and gas commodity prices sustained a significant decline. Prices also affect the amount of cash flow available~~prices. We do not enter into derivative contracts for ~~capital expenditures and our ability~~speculative trading purposes.

We are exposed to ~~borrow and raise additional capital, as, if and when needed. We may use derivative instruments to manage our exposure to commodity price~~market risk ~~from time to time based~~ on our ~~assessment~~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 ~~such risk.~~

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 ~~currently have only a small exposure~~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 ~~policies,~~practices, we do not use interest rate derivative instruments to manage exposure to interest rate changes.

~~ITEM~~

Item 4. ~~CONTROLS AND PROCEDURES~~

Controls and Procedures

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

As required by ~~Securities and Exchange Commission~~SEC Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of ~~the Company’s~~our management, including our ~~Chief~~Principal Executive Officer and ~~Chief~~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 ~~15d-15(e)~~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 ~~Chief~~Principal Executive Officer and ~~Chief~~Principal Financial Officer concluded that as of December 31, ~~2017~~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 ~~Securities and Exchange Commission~~SEC rules and forms.

Under the supervision and with the participation of ~~the Company’s~~our management, including ~~its Chief~~our Principal Executive Officer and ~~Chief~~Principal Financial Officer, during the quarter ended December 31, ~~2017,~~2023, we have determined that there ~~has~~have been no changes in our internal ~~controls~~control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal ~~controls~~control over financial reporting.

~~PART II -~~

Table of Contents

Part II. OTHER INFORMATION

~~ITEM~~

Item 1. ~~LEGAL PROCEEDINGS~~

~~We are involved~~Legal Proceedings

See Note 9, “Commitments and Contingencies” to our unaudited condensed consolidated financial statements in ~~certain~~Item 1. Condensed Consolidated Financial Statements (Unaudited) for a description of any legal proceedings, ~~that are described in our Annual Report on Form 10-K for the year ended June 30, 2017 in Part I. Item 3. “Legal Proceedings” and Note 18 —~~ ~~Commitments and Contingencies~~ under Part II. Item 8. “Financial Statements.” Material developments in the status of those proceedings during the quarter ended December 31, 2017 are described in Part I. Item 1. "Financial Information" under Note 14 — ~~Commitments and Contingencies~~ ~~in this Quarterly Report and~~which is incorporated herein by reference. ~~We believe that the ultimate liability, if any, with respect to these claims and legal actions will not have a material effect on our financial position.~~

~~ITEM~~

Item 1A. ~~RISK FACTORS~~

Risk Factors

Our Annual Report on Form 10-K for the year ended June 30, ~~2017~~2023 includes a detailed description of our risk factors. ~~There have been no material changes to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended June 30, 2017.~~

Table of Contents

~~ITEM~~

Item 2. ~~UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS~~

~~During the quarter ended December 31, 2017, the Company did not sell any equity securities that were not registered under the~~Unregistered Sales of Equity Securities ~~Act.~~

and Use of Proceeds

Issuer Purchases of Equity Securities

During the quarter ended December 31, 2017, the Company received shares of common stock from employees of the Company to pay their share of payroll taxes arising from vestings of restricted stock and contingent restricted stock. During this quarter, the Company did not purchase any common stock in the open market under the previously announced share repurchase program.

The table below summarizes information about the Company's purchases of its equity securities during the ~~quarter~~three months ended December 31, ~~2017.~~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

Period
(a) Total Number of
Shares
Purchased (1)

(b) Average Price
Paid per Share(1)

(c) Total Number of Shares Purchased as Part
of Publicly Announced Plans or Programs (2)

(d) Maximum
Dollar Value
of Shares that
May Yet Be Purchased
Under the Plans or
Programs (2)
October 2017 2,471 $7.03 Not applicable $3.4 million
November 2017 29,001 $7.20 Not applicable $3.4 million
December 2017 8,262 $7.10 Not applicable $3.4 million
Total 39,734 $7.17 Not applicable $3.4 million

~~(1)~~During the current quarter the Company received shares of common stock from certain of its employees which were surrendered in exchange for their payroll tax liabilities arising from vestings of restricted stock and contingent restricted stock. The acquisition cost per share reflects the weighted-average market price of the Company's shares on the dates vested.

~~(2)~~On May 12, 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company's common stock. Under the program's terms, shares may be repurchased only on the open market and in accordance with the requirements

(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 and Exchange Commission. The timing and amount of repurchases will depend upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and the repurchase program may be suspended or discontinued at any time. Such shares are initially recorded as treasury stock, then subsequently canceled.

Not Applicable.

~~ITEM3. DEFAULTS UPON SENIOR SECURITIES~~

Item 4. Mine Safety Disclosures

Not ~~applicable.~~

Applicable.

~~ITEM4. MINE SAFETY DISCLOSURES~~

~~Not applicable.~~

~~ITEM~~

Item 5. ~~OTHER INFORMATION~~Other Information

None.

~~None.~~

Table of Contents

~~ITEM~~

Item 6. ~~EXHIBITS~~

A.Exhibits

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









3.1	Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 of our Quarterly Report on Form 10-Q filed February 8, 2023).
3.3		Amended and Restated Bylaws (incorporated by reference to Exhibit 3.3 of our Annual Report on Form 10- filed September 13, 2023)
~~4.1~~ 31.1**		~~Form of Restricted Stock Agreement under 2016 Equity Incentive Plan (filed herein)~~
~~4.2~~		~~Form of Contingent Restricted Stock Agreement under 2016 Equity Incentive Plan (filed herein)~~
~~10.1~~		Second Amendment to Credit Agreement and Assumption Agreement to Credit Agreement dated April 11, 2016, between Evolution Petroleum Corporation and Midfirst Bank effective February 1, 2018 (filed herein)
~~31.1~~		Certification of ~~Chief~~Principal Executive Officer ~~pursuant~~Pursuant to Rule ~~13a-14(a) or Rule 15d-14(a) under~~15D-14 of the Securities Exchange Act of 1934, as ~~amended.~~Amended as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
~~31.2~~ 31.2**		Certification of ~~Chief~~Principal Financial Officer ~~pursuant~~Pursuant to Rule ~~13a-14(a) or Rule 15d-14(a) under~~15D-14 of the Securities Exchange Act of 1934, as ~~amended.~~Amended as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
~~32.1~~ 32.1**		Certification of ~~Chief~~Principal Executive Officer ~~pursuant to18~~Pursuant to 18 U.S.C. Section 1350, as ~~adopted pursuant~~Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of ~~2002.~~2002
~~32.2~~ 32.2**		Certification of ~~Chief~~Principal Financial Officer ~~pursuant~~Pursuant to 18 U.S.C. Section 1350, as ~~adopted pursuant~~Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of ~~2002.~~2002
~~101.INS~~ 101.INS*		Inline XBRL Instance Document
~~101.SCH~~ 101.SCH*		Inline XBRL Taxonomy Extension Schema Document
~~101.CAL~~ 101.CAL*		Inline XBRL Taxonomy Extension Calculation Linkbase Document
~~101.DEF~~ 101.DEF*		Inline XBRL Taxonomy Extension Definition Linkbase Document
~~101.LAB~~ 101.LAB*		Inline XBRL Taxonomy Extension Label Linkbase Document
~~101.PRE~~ 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.

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~~

~~(Registrant)~~

	Evolution Petroleum Corporation
Date: February 7, 2024	By:	/s/ KELLY W. LOYD
	~~By:~~	~~/s/ RANDALL D. KEYS~~
		~~Randall D. Keys~~
		Kelly W. Loyd President and Chief Executive Officer (Principal Executive Officer) and Director
	By:	/s/ RYAN STASH
~~Date: February 8, 2018~~		Ryan Stash Senior Vice President and Chief Financial Officer (Principal Financial Officer) and Treasurer


Nevada		41-1781991
~~Nevada~~		~~41-1781991~~
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)



	Six Months Ended December 31,
	2017			2016
Cash flows from operating activities
Net income attributable to the Company	$	12,017,380		$	4,124,409
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	3,180,545			2,609,356
Stock-based compensation	971,810			586,872
Accretion of discount on asset retirement obligations	44,602			26,330
Settlements of asset retirement obligations	—			(121,391		)
Deferred income taxes (benefit)	(5,245,910		)	1,709,519
Loss on derivative instruments, net	—			14,042
Changes in operating assets and liabilities:
Receivables	(1,351,451		)	(462,981		)
Prepaid expenses and other current assets	(436,376		)	(367,039		)
Accounts payable and accrued expenses	(83,013		)	(1,955,546		)
Income taxes payable	—			(311,306		)
Net cash provided by operating activities	9,097,587			5,852,265
Cash flows from investing activities
Derivative settlement payments paid	—			(318,618		)
Capital expenditures for oil and natural gas properties	(1,017,358		)	(7,978,130		)
Capital expenditures for other property and equipment	—			(30,447		)
Net cash used in investing activities	(1,017,358		)	(8,327,195		)
Cash flows from financing activities
Cash dividends to preferred stockholders	—			(250,990		)
Cash dividends to common stockholders	(4,969,335		)	(3,801,962		)
Common share repurchases, including shares surrendered for tax withholding	(395,550		)	(459,858		)
Redemption of preferred shares	—			(7,932,975		)
Other	—			32
Net cash used in financing activities	(5,364,885		)	(12,445,753		)
Net increase (decrease) in cash and cash equivalents	2,715,344			(14,920,683		)
Cash and cash equivalents, beginning of period	23,028,153			34,077,060
Cash and cash equivalents, end of period	$	25,743,497		$	19,156,377



Supplemental disclosures of cash flow information:	Six Months Ended December 31,
	2017			2016
Income taxes paid	$	1,136,754		$	1,278,773
Non-cash transactions:
Change in accounts payable used to acquire property and equipment	424,365			(1,516,932		)
Oil and natural gas property costs incurred through recognition of asset retirement obligations	(779		)	—



~~Outstanding Potentially Dilutive Securities~~	~~Weighted~~ ~~Average~~ ~~Exercise Price~~	~~At December 31, 2017~~
~~Contingent Restricted Stock grants~~	—	~~61,868~~



Outstanding Potentially Dilutive Securities	Weighted Average Exercise Price		At December 31, 2016
Contingent Restricted Stock grants	$	—	113,270
Stock Options	2.19		35,231
Total outstanding potentially dilutive securities	$	0.52	148,501


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



Large accelerated filer o	☐	Accelerated filerx	☒	Non-accelerated filer	☐	Smaller reporting company	☒
~~Non-accelerated filer~~ o ~~(Do not check if a smaller reporting company)~~
~~Smaller reporting company~~ o						Emerging growth companyo
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. o ☐



	December 31, 2017		June 30, 2017
Assets
Current assets
Cash and cash equivalents	$	25,743,497	$	23,028,153
Receivables	4,078,153		2,726,702
Prepaid expenses and other current assets	824,048		387,672
Total current assets	30,645,698		26,142,527
Oil and natural gas property and equipment, net (full-cost method of accounting)	60,093,807		61,790,068
Other property and equipment, net	32,265		40,689
Total property and equipment	60,126,072		61,830,757
Other assets	260,468		295,384
Total assets	$	91,032,238	$	88,268,668
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	2,400,202	$	1,994,255
Accrued liabilities and other	660,467		724,639
Total current liabilities	3,060,669		2,718,894
Long term liabilities
Deferred income taxes	10,580,381		15,826,291
Asset retirement obligations	1,297,028		1,253,628
Total liabilities	14,938,078		19,798,813
Commitments and contingencies (Note 14)
Stockholders’ equity
Common stock; par value $0.001; 100,000,000 shares authorized; 33,171,514 and 33,087,308 shares issued and outstanding as of December 31, 2017 and June 30, 2017, respectively	33,171		33,087
Additional paid-in capital	41,538,133		40,961,957
Retained earnings	34,522,856		27,474,811
Total stockholders’ equity	76,094,160		68,469,855
Total liabilities and stockholders’ equity	$	91,032,238	$	88,268,668



	Three Months Ended December 31,						Six Months Ended December 31,
	2017			2016			2017			2016
Revenues
Crude oil	$	10,185,635		$	8,529,817		$	18,014,890		$	16,123,672
Natural gas liquids	881,276			—			1,589,892			89
Natural gas	—			—			—			(4		)
Total revenues	11,066,911			8,529,817			19,604,782			16,123,757
Operating costs
Production costs	2,914,512			2,292,421			5,806,098			4,637,062
Depreciation, depletion and amortization	1,633,868			1,307,510			3,152,411			2,580,949
Accretion of discount on asset retirement obligations	23,023			13,106			44,602			26,330
General and administrative expenses *	1,666,256			1,241,399			3,235,960			2,476,442
Total operating costs	6,237,659			4,854,436			12,239,071			9,720,783
Income from operations	4,829,252			3,675,381			7,365,711			6,402,974
Other
Gain on realized derivative instruments, net	—			—			—			90
Loss on unrealized derivative instruments, net	—			—			—			(14,132		)
Interest and other income	15,841			14,061			30,691			26,806
Interest expense	(20,456		)	(20,711		)	(40,911		)	(41,056		)
Income before income taxes	4,824,637			3,668,731			7,355,491			6,374,682
Income tax provision (benefit)	(5,052,211		)	1,361,097			(4,661,889		)	2,250,273
Net income attributable to the Company	9,876,848			2,307,634			12,017,380			4,124,409
Dividends on preferred stock	—			—			—			250,990
Deemed dividend on redeemed preferred shares	—			—			—			1,002,440
Net income available to common stockholders	$	9,876,848		$	2,307,634		$	12,017,380		$	2,870,979
Earnings per common share
Basic	$	0.30		$	0.07		$	0.36		$	0.09
Diluted	$	0.30		$	0.07		$	0.36		$	0.09
Weighted average number of common shares
Basic	33,109,448			33,047,166			33,099,546			33,002,088
Diluted	33,140,278			33,083,027			33,140,257			33,037,269



	Common Stock
	Common Stock					Additional Paid-in Capital			Retained Earnings			Treasury Stock			Total Stockholders' Equity
	Shares		Par Value			Additional Paid-in Capital			Retained Earnings			Treasury Stock			Total Stockholders' Equity
Balance at June 30, 2017	33,087,308		$	33,087		$	40,961,957		$	27,474,811		$	—		$	68,469,855
Issuance of restricted common stock	158,785		158			(158		)	—			—			—
Forfeitures of restricted stock	(19,561	)	(20		)	20			—			—			—
Common share repurchases, including shares surrendered for tax withholding	(55,018	)	—			—			—			(395,550		)	(395,550		)
Retirements of treasury stock	—		(54		)	(395,496		)	—			395,550			—
Stock-based compensation	—		—			971,810			—			—			971,810
Net income attributable to the Company	—		—			—			12,017,380			—			12,017,380
Common stock cash dividends	—		—			—			(4,969,335		)	—			(4,969,335		)
Balance at December 31, 2017	33,171,514		$	33,171		$	41,538,133		$	34,522,856		$	—		$	76,094,160



	December 31, 2017		June 30, 2017
Receivables from oil and gas sales	$	4,078,153	$	2,722,880
Other	—		3,822
Total receivables	$	4,078,153	$	2,726,702



	December 31, 2017			June 30, 2017
Oil and natural gas properties
Property costs subject to amortization	$	86,403,877		$	84,962,933
Less: Accumulated depreciation, depletion, and amortization	(26,310,070		)	(23,172,865		)
Unproved properties not subject to amortization	—			—
Oil and natural gas properties, net	$	60,093,807		$	61,790,068
Other property and equipment
Furniture, fixtures, office equipment and other, at cost	$	135,377		$	135,377
Less: Accumulated depreciation	(103,112		)	(94,688		)
Other property and equipment, net	$	32,265		$	40,689



	December 31, 2017			June 30, 2017
Royalty rights	$	108,512		$	108,512
Less: Accumulated amortization of royalty rights	(27,128		)	(20,346		)
Investment in Well Lift Inc., at cost	108,750			108,750
Deferred loan costs	168,972			168,972
Less: Accumulated amortization of deferred loan costs	(98,638		)	(70,504		)
Other assets, net	$	260,468		$	295,384



	Number of Restricted Shares	Weighted Average Grant-Date Fair Value
Service-based awards	220,068	$	6.68
Performance-based awards	50,360	5.67
Market-based awards	50,359	5.44
Unvested Restricted Stock at December 31, 2017	320,787	$	6.33



	Number of Restricted Shares		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at December 31, 2017		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2017	391,624		$	6.22
Service-based shares granted	112,155		6.96
Vested	(163,431	)	6.52
Forfeited	(19,561	)	6.16
Unvested Restricted Stock at December 31, 2017	320,787		$	6.33	$	1,510,203	1.39



	Number of Contingent Restricted Shares	Weighted Average Grant-Date Fair Value
Performance-based awards	36,688	$	7.04
Market-based awards	25,180	3.42
Unvested contingent shares at December 31, 2017	61,868	$	5.57



	Three Months Ended December 31,				Six Months Ended December 31,
	2017		2016		2017		2016
Numerator
Net income available to common shareholders	$	9,876,848	$	2,307,634	$	12,017,380	$	2,870,979
Denominator
Weighted average number of common shares — Basic	33,109,448		33,047,166		33,099,546		33,002,088
Effect of dilutive securities:
Contingent restricted stock grants	30,830		9,836		40,711		10,909
Stock options	—		26,025		—		24,272
Weighted average number of common shares and dilutive potential common shares used in diluted EPS	33,140,278		33,083,027		33,140,257		33,037,269

Net income per common share — Basic	$	0.30	$	0.07	$	0.36	$	0.09
Net income per common share — Diluted	$	0.30	$	0.07	$	0.36	$	0.09



Twelve months ended December 31,
2018	$	73,073
2019 (through May)	$	30,447



Period	(a) Total Number of Shares Purchased (1)	(b) Average Price Paid per Share(1)	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)	(d) Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (2)
October 2017	2,471	$7.03	Not applicable	$3.4 million
November 2017	29,001	$7.20	Not applicable	$3.4 million
December 2017	8,262	$7.10	Not applicable	$3.4 million
Total	39,734	$7.17	Not applicable	$3.4 million