EVOLUTION PETROLEUM CORP - Quarter Report: 2021 December (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended December 31, 2021

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

For the transition period from to

Commission File Number 001-32942

EVOLUTION PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)


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

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

(Address of principal executive offices and zip code)

(713) 935-0122

(Registrant’s telephone number, including area code)

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

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

Title of Each Class

Trading Symbol(s)

Name of Each Exchange On Which Registered

Common Stock, $0.001 par value

EPM

NYSE American

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit). Yes: ý No: o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☐

Accelerated filer

☐

Non-accelerated filer

☒

Smaller reporting company

☒

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.). Yes: ☐ No: ☒

APPLICABLE ONLY TO CORPORATE ISSUERS:

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

33,688,679 shares outstanding of common stock, par value $0.001, as of February 7, 2022.

EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

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Forward-Looking Statements		ii
Part I. Financial Information		1
Item 1.	Financial Statements (Unaudited)	1
	Consolidated Condensed Balance Sheets as of December 31, 2021 and June 30, 2021	1
	Consolidated Condensed Statements of Operations for the three and six months ended December 31, 2021 and 2020	2
	Consolidated Condensed Statements of Cash Flows for the six months ended December 31, 2021 and 2020	3
	Consolidated Condensed Statements of Changes in Stockholders’ Equity for the three and six months ended December 31, 2021 and 2020	4
	Notes to Consolidated Condensed Financial Statements	5
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	17
Item 3.	Quantitative and Qualitative Disclosures about Market Risks	29
Item 4.	Controls and Procedures	29
Part II. Other Information		31
Item 1.	Legal Proceedings	31
Item 1A.	Risk Factors	31
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31
Item 3.	Defaults Upon Senior Securities	31
Item 4.	Mine Safety Disclosures	31
Item 5.	Other Information	31
Item 6.	Exhibits	31
Signatures		32

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

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FORWARD-LOOKING STATEMENTS

This Form 10-Q and the information referenced herein contains forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words “plan,” “expect,” “project,” “estimate,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict,” and other similar expressions are intended to identify forward-looking statements. 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. When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks, and other risk factors as described in Part II, Item 1A, “Risk Factors” and elsewhere in this report and as also may be described from time to time in our future reports we file with the Securities and Exchange Commission. You should read such information in conjunction with our consolidated condensed financial statements and related notes and “Management's Discussion and Analysis of Financial Condition and Results of Operations” in this report. 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. You are advised, however, to review any further disclosures we make on related subjects in our periodic filings with the Securities and Exchange Commission.

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Balance Sheets

(Unaudited)


	December 31, 2021		June 30, 2021
Assets
Current assets
Cash and cash equivalents	$	13,597,156	$	5,276,510
Receivables from oil, natural gas liquids, and natural gas sales	12,594,910		8,686,967
Receivables for federal and state income tax refunds	2,428,887		3,107,638
Receivable for settlement proceeds from prior year Barnett Shale acquisition	1,882,233		—
Prepaid expenses and other current assets	852,636		1,037,259
Total current assets	31,355,822		18,108,374
Property and equipment, net of depreciation, depletion, amortization, and amortization
Oil and natural gas properties—full-cost method of accounting, of which none were excluded from amortization	55,752,039		58,515,860
Other property and equipment, net	6,737		10,639
Total property and equipment, net	55,758,776		58,526,499
Other assets, net	46,510		70,789
Total assets	$	87,161,108	$	76,705,662
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable	$	8,188,421	$	5,609,367
Accrued liabilities and other	572,260		947,045

State and federal income taxes payable	606,445		37,748
Total current liabilities	9,367,126		6,594,160
Long term liabilities
Senior secured credit facility	4,000,000		4,000,000
Deferred income taxes	5,902,924		5,957,202
Asset retirement obligations	5,764,567		5,538,752
Operating lease liability	—		20,745
Total liabilities	25,034,617		22,110,859
Commitments and contingencies (Note 14)
Stockholders’ equity
Common stock; par value $0.001; 100,000,000 shares authorized; 33,688,679 and 33,514,952 shares issued and outstanding as of December 31, 2021 and June 30, 2021, respectively	33,689		33,515
Additional paid-in capital	43,066,954		42,541,224
Retained earnings	19,025,848		12,020,064
Total stockholders’ equity	62,126,491		54,594,803
Total liabilities and stockholders’ equity	$	87,161,108	$	76,705,662

See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Operations

(Unaudited)


	Three Months Ended December 31,			Six Months Ended December 31,
		2021		2020		2021		2020
Revenues
Oil		$	10,582,145	$	5,462,783	$	19,440,608	$	10,841,944
Natural gas liquids		2,586,758		305,200		7,148,976		521,226
Natural gas		9,169,458		169		14,627,787		358
Total revenues		22,338,361		5,768,152		41,217,371		11,363,528
Operating costs
Lease operating costs		10,670,974		3,005,413		19,296,141		5,403,337
Depreciation, depletion, and amortization		1,223,721		1,358,168		2,751,533		2,769,056
Impairment of proved property		—		15,189,459		—		24,792,079
Net loss on derivative contracts		—		279,679		—		614,645
General and administrative expenses *		1,823,245		1,845,699		3,763,154		3,124,397
Total operating costs		13,717,940		21,678,418		25,810,828		36,703,514
Income (loss) from operations		8,620,421		(15,910,266)		15,406,543		(25,339,986)
Other
Interest and other income		7,293		11,217		9,770		25,643
Interest expense		(50,930)		(19,622)		(101,542)		(41,654)
Income (loss) before income taxes		8,576,784		(15,918,671)		15,314,771		(25,355,997)
Income tax expense (benefit)		1,744,612		(3,208,664)		3,264,198		(5,510,842)
Net income (loss) attributable to common stockholders		$	6,832,172	$	(12,710,007)	$	12,050,573	$	(19,845,155)
Earnings (loss) per common share
Basic		$	0.20	$	(0.38)	$	0.36	$	(0.60)
Diluted		$	0.20	$	(0.38)	$	0.36	$	(0.60)
Weighted average number of common shares outstanding
Basic		33,645,982		33,106,885		33,589,986		33,031,270
Diluted		33,645,982		33,106,885		33,589,986		33,031,270

* General and administrative expenses for the three months ended December 31, 2021 and 2020 included non-cash stock-based compensation expenses of $329,677 and $317,506, respectively. For the six months ended December 31, 2021 and 2020, non-cash stock-based compensation expenses were $527,503 and $617,857, respectively.

See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Cash Flows

(Unaudited)


	Six Months Ended December 31,
	2021		2020
Cash flows from operating activities
Net income (loss) attributable to common stockholders	$	12,050,573	$	(19,845,155)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	2,751,533		2,769,056
Impairment of proved property	—		24,792,079
Stock-based compensation	527,503		617,857
Settlement of asset retirement obligations	—		(100,389)
Deferred income taxes	(54,278)		(5,766,747)
Net loss on derivative contracts	—		614,645
Payments paid for derivative settlements	—		(2,137,225)
Other	(4,496)		7,475
Changes in operating assets and liabilities:
Receivables	(4,253,003)		(457,336)
Prepaid expenses and other current assets	184,623		91,248
Net operating loss carryback	—		(110,942)
Accounts payable and accrued expenses	2,122,157		875,390
Income taxes payable	568,697		(125,999)
Net cash provided by operating activities	13,893,309		1,223,957
Cash flows from investing activities

Development of oil and natural gas properties	(526,275)		(182,935)


Net cash provided by (used in) investing activities	(526,275)		(182,935)
Cash flows from financing activities
Common stock dividends paid	(5,044,789)		(1,661,110)
Common share repurchases, including shares surrendered for tax withholding	(1,599)		(7,348)

Net cash used in financing activities	(5,046,388)		(1,668,458)
Net increase (decrease) in cash and cash equivalents	8,320,646		(627,436)
Cash and cash equivalents, beginning of period	5,276,510		19,662,528
Cash and cash equivalents, end of period	$	13,597,156	$	19,035,092

See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Changes in Stockholders' Equity

(Unaudited)


	Common Stock			Additional Paid-in Capital		Retained Earnings		Treasury Stock		Total Stockholders' Equity
	Shares	Par Value
For the Three Months Ended December 31, 2021:
Balance at September 30, 2021	33,631,749	$	33,632	$	42,737,334	$	14,716,057	$	—	$	57,487,023
Issuance of restricted common stock	56,930	57		(57)		—		—		—
Forfeitures and expirations of restricted stock	—	—		—		—		—		—
Common share repurchases, including shares surrendered for tax withholding	—	—		—		—		—		—
Retirements of treasury stock	—	—		—		—		—		—
Stock-based compensation	—	—		329,677		—		—		329,677
Net income attributable to common stockholders	—	—		—		6,832,172		—		6,832,172
Common stock cash dividends paid	—	—		—		(2,522,381)		—		(2,522,381)
Balance at December 31, 2021	33,688,679	$	33,689	$	43,066,954	$	19,025,848	$	—	$	62,126,491

For the Six Months Ended December 31, 2021:
Balance at June 30, 2021	33,514,952	$	33,515	$	42,541,224	$	12,020,064	$	—	$	54,594,803
Issuance of restricted common stock	253,870	254		(254)		—		—		—
Forfeitures and expirations of restricted stock	(79,790)	(80)		80		—		—		—
Common share repurchases, including shares surrendered for tax withholding	—	—		—		—		(1,599)		(1,599)
Retirements of treasury stock	(353)	—		(1,599)		—		1,599		—
Stock-based compensation	—	—		527,503		—		—		527,503
Net income attributable to common stockholders	—	—		—		12,050,573		—		12,050,573
Common stock dividends paid	—	—		—		(5,044,789)		—		(5,044,789)
Balance at December 31, 2021	33,688,679	$	33,689	$	43,066,954	$	19,025,848	$	—	$	62,126,491

For the Three Months Ended December 31, 2020:
Balance at September 30, 2020	32,953,837	$	32,953	$	41,584,452	$	24,841,086	$	—	$	66,458,491
Issuance of restricted common stock	536,713	537		(537)		—		—		—
Forfeitures and expirations of restricted stock	—	—		—		—		—		—
Common share repurchases, including shares surrendered for tax withholding	—	—		—		—		—		—
Retirements of treasury stock	—	—		—		—		—		—
Stock-based compensation	—	—		317,506		—		—		317,506
Net income attributable to common stockholders	—	—		—		(12,710,007)		—		(12,710,007)
Common stock dividends paid	—	—		—		(837,264)		—		(837,264)
Balance at December 31, 2020	33,490,550	$	33,490	$	41,901,421	$	11,293,815	$	—	$	53,228,726

For the Six Months Ended December 31, 2020:
Balance at June 30, 2020	32,956,469	$	32,956	$	41,291,446	$	32,800,080	$	—	$	74,124,482
Issuance of restricted common stock	536,713	537		(537)		—		—		—
Forfeitures and expirations of restricted stock	—	—		—		—		—		—
Common share repurchases, including shares surrendered for tax withholding	—	—		—		—		(7,348)		(7,348)
Retirements of treasury stock	(2,632)	(3)		(7,345)		—		7,348		—
Stock-based compensation	—	—		617,857		—		—		617,857
Net loss attributable to common stockholders	—	—		—		(19,845,155)		—		(19,845,155)
Common stock dividends paid	—	—		—		(1,661,110)		—		(1,661,110)
Balance at December 31, 2020	33,490,550	$	33,490	$	41,901,421	$	11,293,815	$	—	$	53,228,726

See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

Note 1 — Organization and Basis of Preparation

Nature of Operations. Evolution Petroleum Corporation is an oil and natural gas company focused on delivering a sustainable dividend yield to its stockholders through the ownership, management, and development of producing oil and natural gas properties. The Company's long-term goal is to build a diversified portfolio of oil and natural gas assets primarily through acquisitions while seeking opportunities to maintain and increase production through selective development, production enhancement, and other exploitation efforts on its properties.

The Company’s producing assets consist of interests in the Delhi Holt-Bryant Unit in the Delhi field in Northeast Louisiana, a CO2 enhanced oil recovery (“EOR”) project, interests in the Hamilton Dome field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir, interests in the Barnett Shale located in North Texas, a natural gas producing shale reservoir, and minimal overriding royalty interests in four onshore Texas wells.

Interim Financial Statements. The accompanying unaudited consolidated condensed financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) for interim financial information and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. All adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods presented have been included. The interim financial information and notes hereto should be read in conjunction with the Company’s 2021 Annual Report on Form 10-K for the fiscal year ended June 30, 2021, as filed with the SEC on September 14, 2021. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year. The Company has evaluated events and transactions through the date of issuance of these unaudited consolidated condensed financial statements.

Principles of Consolidation and Reporting. The Company’s unaudited consolidated condensed financial statements include the accounts of Evolution Petroleum Corporation and its wholly-owned subsidiaries (the “Company”). All significant intercompany transactions have been eliminated in consolidation.

Risk and Uncertainties. The Company is continuously monitoring the current and potential impacts of the COVID-19 pandemic on its business, including how it has and may continue to impact its financial results, liquidity, employees, and the operations of the Delhi field, Hamilton Dome field, and its Barnett Shale assets in which it holds non-operated interests.

All of the Company’s property interests are not operated by the Company and involve other third-party working interest owners. As a result, the Company has limited ability to influence or control the operation or future development of such properties. However, the Company has been proactive with its third-party operators to review spending and alter plans as appropriate.

In response to the COVID-19 pandemic, the Company has focused on putting long-term measures in place to prevent future disruptions, maintaining its operations and system of controls remotely, and has implemented its business continuity plans in order to allow its employees to securely work from home or in the corporate office. The Company has been able to transition the operation of its business with minimal disruption and has maintained its system of internal controls and procedures.

Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include (a) reserve quantities and estimated future cash flows associated with proved reserves, which may significantly impact depletion expense and potential impairments of oil and natural gas properties, (b) asset retirement obligations, (c) stock-based compensation, (d) fair values of derivative assets and liabilities, (e) income taxes and the valuation of deferred tax assets, (f) commitments and contingencies, and (g) oil, natural gas, and natural gas liquids (“NGL”) revenues. The Company analyzes estimates based on historical experience and various other assumptions that are believed to be reasonable. While the Company believes that the estimates and assumptions used in preparation of the unaudited consolidated condensed financial statements are appropriate, actual results could differ from those estimates.

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Evolution Petroleum Corporation and Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

Note 2 — Summary of Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 2 - Summary of Significant Accounting Policies in the 2021 Form 10-K and are supplemented by the notes to the unaudited consolidated condensed financial statements included in this report. These unaudited consolidated condensed financial statements should be read in conjunction with the 2021 Form 10-K.

Recently Issued Accounting Pronouncements

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

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

Note 3 — Revenue Recognition

The Company’s revenue is primarily generated from our interests in the Delhi field in Northeast Louisiana, the Barnett Shale assets of North Texas, and the Hamilton Dome field in Wyoming. Additionally, overriding royalty interests retained in a past divestiture of Texas properties historically provided de minimis revenue, with the exception of the three months ended December 31, 2021 in which the Company received $1.1 million for past royalties that accumulated over a period of approximately three years. Going forward, the Company expects de minimis revenue from these royalty interests.


	Three Months Ended December 31,				Six Months Ended December 31,
	2021		2020		2021		2020
Revenues
Oil	$	10,582,145	$	5,462,783	$	19,440,608	$	10,841,944
Natural gas liquids	2,586,758		305,200		7,148,976		521,226
Natural gas	9,169,458		169		14,627,787		358
Total revenues	$	22,338,361	$	5,768,152	$	41,217,371	$	11,363,528

As a non-operator, the Company does not presently take production in-kind and does not negotiate contracts with customers. Evolution recognizes oil, natural gas, and natural gas liquids production revenue at the point in time when custody and title (“control”) of the product transfers to the customer. Transfer of control drives the presentation of post-production expenses such as transportation, gathering, and processing deductions within the accompanying statements of operations. Fees and other deductions incurred prior to control transfer are recorded within the lease operating costs line item on the accompanying unaudited consolidated condensed statements of operations, while fees and other deductions incurred subsequent to control transfer are embedded in the price and effectively recorded as a reduction of oil, natural gas, and natural gas liquids production revenue. Transfer of control related to the Barnett Shale production does not occur until after the marketing, transportation, and processing services have been performed, and as such, fees related to these services are recorded within the lease operating costs line item and do not reduce the oil, natural gas, and natural gas liquids production revenue. Transfer of control related to the Hamilton Dome and Delhi production occurs prior to the fees and other deductions, and as such, these fees are recorded as a reduction to the oil and natural gas liquids production revenue.

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

The Company’s contractual performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied at a point in time upon control

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Evolution Petroleum Corporation and Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

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 before distributing the Company's share one to two months after production has occurred, which is typical in the 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 the field operators, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Estimated revenue due to the Company is recorded within the “Receivables from oil and natural gas sales” line item on the accompanying unaudited consolidated condensed balance sheets until payment is received from field operators. The accounts receivable balances from contracts with customers as presented on our respective unaudited consolidated condensed balance sheet as of December 31, 2021 and derived from the audited consolidated balance sheet as of June 30, 2021, were $12.6 million and $8.7 million, respectively. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser as remitted to us by field operators. Revenue recognized during the six months ended December 31, 2021, related to performance obligations satisfied in prior reporting periods, was immaterial.

Note 4 — Prepaid Expenses and Other Current Assets


	December 31, 2021		June 30, 2021
Prepaid insurance	$	170,236	$	365,922
Prepaid subscription and licenses	71,734		108,048
Prepaid federal and state income taxes	177,212		97,470
Carryback of EOR tax credit	416,441		416,441
Prepaid other	17,013		49,378
Total prepaid expenses and other current assets	$	852,636	$	1,037,259

Note 5 — Property and Equipment


	December 31, 2021		June 30, 2021
Oil and natural gas properties:
Property costs subject to amortization	$	128,903,479	$	129,123,227
Less: Accumulated depreciation, depletion, amortization and impairment (a)	(73,151,440)		(70,607,367)
Oil and natural gas properties, net	$	55,752,039	$	58,515,860
Other property and equipment:
Furniture, fixtures, and office equipment, at cost	$	154,732	$	154,731
Less: Accumulated depreciation (b)	(147,995)		(144,092)
Other property and equipment, net	$	6,737	$	10,639

(a) Depletion on oil and natural gas properties was $2,544,072 for the six months ended December 31, 2021, and $2,670,801 for the six months ended December 31, 2020. There was no impairment on oil and natural gas properties for the six months ended December 31, 2021. The Company recorded an impairment of $24.8 million for the six months ended December 31, 2020.

(b) Depreciation was $3,902 for the six months ended December 31, 2021, and $3,620 for the six months ended December 31, 2020.

As of December 31, 2021, all oil and natural gas property costs were subject to amortization.

During the six months ended December 31, 2021 and 2020, the Company incurred development capital expenditures of $0.6 million and $0.2 million, respectively. In addition, during the six months ended December 31, 2021, the Company recorded a downward $0.9 million purchase adjustment related to its acquisition of the Barnett Shale assets.

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Evolution Petroleum Corporation and Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

On May 7, 2021, the Company acquired an approximate 17% working interest and a 14% revenue interest in non-operated oil and natural gas assets in the Barnett Shale from Tokyo Gas Americas for $17.4 million, net of purchase price adjustments, and also recognized $2.8 million in non-cash asset retirement obligations (the “Barnett Shale Acquisition”). As of December 31, 2021, there was $1.8 million in receivables representing expected proceeds from Tokyo Gas related to the final settlement The Company accounted for this transaction as an asset acquisition with an effective date of January 1, 2021.

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

The Company uses the full cost method of accounting for its investment in oil and natural gas properties. All costs of acquisition, exploration, and development of oil and natural gas reserves are capitalized as the cost of oil and natural gas and properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs result in an impairment charge.

At December 31, 2021, 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, 2021 of the West Texas Intermediate (WTI) crude oil spot price of $66.55

per barrel and Henry Hub natural gas spot price of $3.64 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $26.54, which was based on historical prices received as NGLs do not have any single comparable reference index price. Using these prices, the Company’s net book value of oil and natural gas properties at December 31, 2021 was below the current ceiling.

Note 6 — Other Assets


	December 31, 2021		June 30, 2021





Right of use asset under operating lease	161,125		161,125
Less: Accumulated amortization of right of use asset	(114,615)		(90,336)


Other assets, net	$	46,510	$	70,789

Operating leases are reflected as an operating lease right of use (“ROU”) asset included in “Other assets, net”, and as a ROU liability in “Accrued liabilities and other” (see Note 7 below) and “Operating lease liability” on the Company’s consolidated condensed balance sheets. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term and amortized on a straight-line basis over the lease term. The ROU asset reflected in “Other Assets, net” above is related to the Company’s corporate office lease.

Note 7 — Accrued Liabilities and Other


	December 31, 2021		June 30, 2021
Accrued incentive and other compensation	$	398,167	$	630,744
Accrued retirement costs	7,425		52,786
Accrued franchise taxes	60,208		35,207
Accrued ad valorem taxes	—		108,000

Operating lease liability, current	56,204		64,234
Asset retirement obligations due within one year	22,264		44,520
Accrued - other	27,992		11,554
Total accrued liabilities and other	$	572,260	$	947,045

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Evolution Petroleum Corporation and Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

Note 8 — Asset Retirement Obligations

The Company’s asset retirement obligations represent the estimated present value of the amount expected to incur to plug, abandon, and remediate its oil and natural gas assets at the end of their productive lives in accordance with applicable laws and regulations. Currently, the Company does not expect any wells to be plugged for the remainder of the fiscal year ended June 30, 2022 at its Delhi or Barnett Shale assets. The Company expects to incur costs for one well to be plugged at Hamilton Dome prior to the fiscal year end. The following is a reconciliation of the beginning and ending asset retirement obligations for the six months ended December 31, 2021 and for the year ended June 30, 2021:


	December 31, 2021		June 30, 2021
Asset retirement obligations — beginning of period	$	5,583,272	$	2,588,894
Liabilities incurred	—		—
Liabilities settled	—		(99,231)		(a)
Liabilities acquired	—		2,806,331		(b)
Accretion of discount	203,559		210,182
Revision of previous estimates	—		77,096		(c)
Asset retirement obligations — end of period	$	5,786,831	$	5,583,272
Less: current asset retirement obligations	22,264		44,520
Long-term portion of asset retirement obligations	$	5,764,567	$	5,538,752

(a) Abandonment of two non-scheduled Delhi field wells in fiscal 2021.

(b) Liabilities acquired in fiscal 2021 were primarily due to the acquisition of the Barnett Shale assets.

Note 9 — Stockholders’ Equity

Common Stock

As of December 31, 2021, the Company had 33,688,679 shares of common stock outstanding.

The Company began paying quarterly cash dividends on common stock in December 2013. As of December 31, 2021, Evolution has cumulatively paid over $79.5 million in cash dividends. We paid dividends of $5,044,789 and $1,661,110 to our common stockholders during the six months ended December 31, 2021 and 2020, respectively. The following table reflects the dividends paid within each respective three-month period:


Common Stock Cash Dividends per Share	2021		2020
First quarter ended September 30,	$	0.075	$	0.025
Second quarter ended December 31,	$	0.075	$	0.025

In May 2015, the Board of Directors approved a share repurchase program covering up to $5.0 million of the Company's common stock. Since inception of the program through December 31, 2021, the Company spent $4.0 million to repurchase 706,858 common shares at an average price of $5.72 per share. There were no shares repurchased under this program during the six months ended December 31, 2021. Under the program's terms, shares are repurchased only on the open market and in accordance with the requirements of the SEC. 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 market and business conditions. There is no fixed termination date for this repurchase program, and it may be suspended or discontinued at any time.

During the six months ended December 31, 2021 and 2020, the Company acquired treasury stock from holders of newly vested stock-based awards to fund the recipients' payroll tax withholding obligations. The treasury shares were subsequently canceled. Such shares were valued at fair market value on the date of vesting. The following table shows all treasury stock purchases in the respective periods:

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Evolution Petroleum Corporation and Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements


	Six Months Ended December 31,
	2021		2020
Number of treasury shares acquired	353		2,632
Average cost per share	$	4.53	$	2.79
Total cost of treasury shares acquired	$	1,599	$	7,348

Expected Tax Treatment of Dividends

For the fiscal year ended June 30, 2021, all common stock dividends were treated for tax purposes as qualified dividend income to recipients. Based on current projections for the fiscal year ending June 30, 2022, the Company expects all common stock dividends for such period to be treated as qualified dividend income to the recipients. Such projections are based on reasonable expectations as of December 31, 2021 and are subject to change based on the final tax calculations at the end of the fiscal year.

Note 10 — Stock-Based Incentive Plan

The Evolution Petroleum Corporation 2016 Equity Incentive Plan ("2016 Plan"), approved in the December 2016 annual meeting, authorized the issuance of 1,100,000 shares of common stock prior to its expiration on December 8, 2026. On December 9, 2020, an amendment to the 2016 Plan was approved by the Company’s stockholders which increased the number of shares available for issuance by 2,500,000 shares. Incentives under the 2016 Plan may be granted to employees, directors, and consultants of the Company in any one or a combination of the following forms: incentive stock options and non-statutory stock options, stock appreciation rights, restricted stock awards and restricted stock unit awards, performance share awards, performance cash awards, and other forms of incentives valued in whole or in part by reference to, or otherwise based on, the Company’s common stock, including its appreciation in value. There were 1,952,424 shares available for grant under the 2016 Plan as of December 31, 2021.

Time-Vested Restricted Stock

These awards contain service-based vesting conditions and expire after a maximum of four years from the date of grant if unvested. The common shares underlying these awards are issued on the date of grant and participate in dividends paid by the Company. These serviced-based awards vest with continuous employment by the Company, generally in annual installments over terms of three to four years. Awards to the Company's directors 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 term of the grant. Previously recognized amortization expense subsequent to the last vesting date of an award is reversed in the event that the holder has no longer rendered service to the Company resulting in forfeiture of the award.

Performance-Based Restricted Stock and Performance-Based Contingent Shares

Presently under the Plan, the Company has only granted such awards having market-based vesting conditions based on the price of its common stock, the intrinsic value indexed solely to its common stock and the intrinsic value indexed to its common stock compared to the performance of the common stock of its peers. While the Plan also provides for awards whose vesting is based upon other performance conditions that relate to attaining Company-specific operating goals such as earnings, revenues, and other operational goals, no such awards have been granted under the Plan nor have any such awards previously granted by legacy plans been outstanding during the six-months ended December 31, 2021 and 2020.

The common shares underlying our Performance-Based Restricted Stock awards are issued on the date of grant and participate in dividends paid by the Company and expire after a maximum of four years from the date of grant if unvested. Performance-Based Contingent Shares do not participate in dividends and shares are only issued upon the attainment of vesting conditions which generally have a lower probability of achievement and expire after a maximum of four years from the date of grant if unvested. Shares underlying Performance-Based Contingent Shares are reserved from the Plan.

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

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Evolution Petroleum Corporation and Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

price. As discussed below, a third party valuation firm estimates the grant date fair value of the the award as well as the expected vesting period. This value is amortized ratably over the expected vesting period, which may be less than the term of the grant. 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.

During six months ended December 31, 2021, a total of 262,589 equity awards were granted related to Evolution’s fiscal year 2022 long-term incentive pay program that included 65,647 shares of Time-Vested Restricted Stock, which vests in three equal amounts on June 30, 2022, 2023 and 2024, 131,293 shares of Performance-Based Restricted Stock, and the Company granted 65,649 Performance-Based Contingent Share awards. In December 2021, 56,930 Time-Vested Restricted Stock were granted to the Company’s directors.

During six months ended December 31, 2020, the Company granted 290,553 shares of Time-Vested Restricted Stock, primarily to employees under its long-term incentive pay program together with annual awards to directors. In addition, under this program, the Company issued 246,160 shares of Performance-Based Restricted Stock and granted 123,080 Performance-Based Contingent Share awards its employees. In addition to the foregoing, in connection with the retirement of the Company's former Chief Financial Officer, vesting was accelerated as to 50,524 aggregate shares of service- and market-based equity awards which, for accounting purposes, was treated as a cancellation and replacement of the same number of awards.

As mentioned above for awards with market-based vesting conditions, the Company utilizes third-party independent assessments of grant date fair values and expected vesting periods that are determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other peer companies in the index. During the six months ended December 31, 2021 and six months ended December 31, 2020, the assumptions used in the Monte Carlo simulation valuations were as follows:


	December 31,		December 31,
	2021		2020
Weighted average fair value of market-based awards granted	$	3.10	$	3.08
Risk-free interest rate	0.53% to 0.60%		0.23		%
Expected vesting term in years	2.64 to 2.79		2.56
Expected volatility	64.7% to 64.7%		56.9		%
Dividend yield	4.8% to 6.3%		3.2		%

Unvested restricted stock awards at December 31, 2021 consisted of the following:


	Number of Shares of Restricted Stock	Weighted Average Grant-Date Fair Value
Time-Vested Restricted Stock awards	271,636	$	4.13

Performance-Based Restricted Stock awards	382,071	3.34
Unvested Shares of Restricted Stock at December 31, 2021	653,707	$	3.67

The following table sets forth the restricted stock transactions for the six months ended December 31, 2021:


	Number of Shares of Restricted Stock	Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at December 31, 2021		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2021	669,295	$	3.37
Time-Vested Restricted Stock shares granted	122,577	4.99
Performance-Based Restricted Stock shares granted	131,293	3.31
Vested	(170,884)	3.27
Forfeited and expired	(98,574)	3.52
Unvested Shares of Restricted Stock at December 31, 2021	653,707	$	3.67	$	1,737,057	1.86

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Evolution Petroleum Corporation and Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

The following table sets forth the contingent share transactions for the six months ended December 31, 2021:


	Number of Performance- Based Contingent Shares	Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at December 31, 2021		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2021	323,080	$	2.84
Performance-Based Contingent Shares granted	65,649	2.67

Forfeited	(26,402)	$	1.89

Unvested Performance-Based Contingent Shares at December 31, 2021	362,327	$	2.88	$	259,414	2.1

Stock-based Compensation Expense

Expense related to all of the above equity awards for the three months ended December 31, 2021 and 2020 was $329,677 and $317,506, respectively. Expense for the six months ended December 31, 2021 and 2020 was $527,503 and $617,857, respectively.

Note 11 — Income Taxes

We file a consolidated federal income tax return in the United States of America in addition to 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 any periods presented in these unaudited consolidated condensed financial statements. We believe that we have 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 our 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, 2018 through June 30, 2021 for federal tax purposes and for the fiscal years ended June 30, 2017 through June 30, 2021 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.

For the six months ended December 31, 2021, we recognized income tax expense of $3.3 million and had an effective tax rate of 21.3% compared to an income tax benefit of $5.5 million and an effective tax rate of 21.7% for the six months ended December 31, 2020.

Our effective tax rate will typically differ from the statutory federal rate as a result of state income taxes, primarily in the states of Louisiana and Texas, and differences related to percentage depletion in excess of basis, stock-based compensation, and other permanent differences. For both periods, our respective statutory federal tax rate was 21%.

At December 31, 2021, the Company has a $2.4 million receivable for the remainder of income tax refunds from its amended federal and state tax returns for fiscal 2017 and 2018 for Enhanced Oil Recovery (“EOR”) credits related to our Delhi field interests as well as a refund for its fiscal 2019 federal tax return. Subsequent to filing these returns, the Company has received $0.8 million of income tax refunds, and the Company currently anticipates receiving the remaining refund within the next twelve months based on inquiries and communication with the Internal Revenue Service, although no assurances can be made as to the actual date of receipt. During the six months ended December 31, 2021, we recognized an income tax benefit of $0.2 million attributable to the EOR credit.

We must assess the likelihood that we will be able to realize our deferred tax assets. Realization is dependent on generating sufficient taxable income over the period the deferred tax assets are deductible. Currently, the Company is in a cumulative taxable loss position, but with the increase in commodity prices and absent material unexpected losses, the Company may be in a cumulative taxable income position during the current fiscal year. Management considered the reversal of deferred tax liabilities and tax planning strategies in assessing the realization of deferred tax assets. Based upon the weight of available evidence, the Company believes that some of the deferred tax assets are not likely to be realized at the time of this report. For the six months ended December 31, 2021, there was no material change in the valuation allowance related to the federal and state deferred tax assets.

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Evolution Petroleum Corporation and Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

Note 12 — Earnings (Loss) per Common Share

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


	Three Months Ended December 31,				Six Months Ended December 31,
	2021		2020		2021		2020
Numerator
Net income (loss) attributable to common stockholders	$	6,832,172	$	(12,710,007)	$	12,050,573	$	(19,845,155)
Denominator
Weighted average number of common shares — basic and diluted	33,645,982		33,106,885		33,589,986		33,031,270




Net earnings (loss) per common share — Basic	$	0.20	$	(0.38)	$	0.36	$	(0.60)
Net earnings (loss) per common share — Diluted	$	0.20	$	(0.38)	$	0.36	$	(0.60)


Outstanding Potentially Dilutive Securities	Weighted Average Exercise Price		Outstanding at December 31, 2021
Contingent Share grants	$	—	362,327


Outstanding Potentially Dilutive Securities	Weighted Average Exercise Price		Outstanding at December 31, 2020
Contingent Share grants	$	—	323,080

Note 13 — Senior Secured Credit Agreement

On April 11, 2016, the Company entered into a three-year, senior secured reserve-based credit facility (the “Senior Secured Credit Facility”) in an amount up to $50 million. On November 2, 2020, the Company entered into the Fifth Amendment to the Senior Secured Credit Facility extending the maturity to April 9, 2024. On August 5, 2021, and effective as of June 30, 2021, the Company entered into the Seventh Amendment of the Senior Secured Credit Facility which added definitions for the terms “Acquired Entity or Mineral Interests” and “Acquired Entity or Mineral Interests EBITDA Adjustment.” Additionally, the Consolidated Tangible Net Worth covenant level was reduced to $40 million from $50 million. On November 9, 2021, the Company entered into the Eighth Amendment to the Senior Secured Credit Facility. This amendment increased the borrowing base to $50 million and added a hedging covenant whereby the Company must hedge from 25 to 75 percent of future production on a rolling twelve-month basis when 25 percent or more of the borrowing base is utilized. The Company has elected a $40 million commitment amount for the Senior Secured Credit Facility. On February 7, 2022, the Company entered into the Ninth Amendment to the Senior Secured Credit Facility. This amendment modified the definition of utilization percentage related to the required hedging covenant such that for the purposes of determining the amount of future production to hedge, the utilization of the Senior Secured Credit Facility will be based on the calculated collateral value to the extent it exceeds the borrowing base then in effect. See Note 18- Subsequent Events, for further information.

At December 31, 2021 the Company was in compliance with the financial covenants under the Senior Secured Credit Facility, which is secured by substantially all of the Company's assets. At December 31, 2021, the Company had $4.0 million outstanding under its Senior Secured Credit Facility, resulting in $36.0 million of available borrowing capacity.

Borrowings from the Senior Secured Credit Facility may be used for the acquisition and development of oil and natural gas properties, investments in cash flow generating assets complimentary to the production of oil and natural gas, and for letters of credit or other general corporate purposes.

The Senior Secured Credit Facility included a placement fee of 0.50% on the initial borrowing base amounting to $50 million and 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 London Interbank Offered Rate (“LIBOR”) plus 2.75%, subject to a minimum LIBOR of 0.25%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%. The Senior Secured Credit 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 current ratio of not less than 1.00 to 1.00, and (c) a consolidated tangible net worth of not less than $40 million, all as defined under the

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Evolution Petroleum Corporation and Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

Senior Secured Credit Facility.

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 material loss through the impairment of an asset or the incurrence of a material liability. We accrue a material loss if we believe it is probable that a future event or events will confirm a loss, 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 and material in amount. We expense legal defense costs as they are incurred.

Note 15 – Derivatives

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 December 31, 2021 and 2020, the Company did not have any open derivative contracts.

The Company has in the past and may utilize in the future fixed-price swaps or costless put/call collars to hedge a portion of its anticipated future production. 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. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract, and a purchased put that establishes a minimum price. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of the derivative contracts and all payments and receipts on settled derivative contracts in “Net loss on derivative contracts” on the unaudited consolidated condensed statements of operations.


	Three Months Ended December 31,				Six Months Ended December 31,
	2021		2020		2021		2020
Realized loss	$	—	$	1,374,412	$	—	$	2,525,988
Unrealized gain	—		(1,094,733)		—		(1,911,343)
Net loss on derivative contracts	$	—	$	279,679	$	—	$	614,645

All derivative contracts are recorded at fair market value and is included in the unaudited consolidated condensed balance sheets as an asset or a liability.

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

Note 16 – Fair Value Measurement

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

The three levels are defined as follows:

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

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

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Evolution Petroleum Corporation and Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

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

Fair Value of Derivative Instruments. The Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s 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 – Fair Value Measurement (“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 are generally market corroborated (Level 2), and the Company classifies fair value balances as such. The Company did not have any open derivative trades as of December 31, 2021, and 2020.

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 judgment. This may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any period presented in this report.

Other Fair Value Measurements. The initial measurement and any subsequent revision of asset retirement obligations at fair value are calculated using discounted future cash flows of internally estimated costs. Significant Level 3 inputs used in the calculation of asset retirement obligations 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 the Company’s asset retirement obligations.

Note 17 – Supplemental Disclosure of Cash Flow Information


Supplemental disclosures of cash flow information:	Six Months Ended December 31,
	2021		2020
Income taxes paid	$	2,868,408	$	561,852
Income tax refunds received	678,751		130,499
Non-cash transactions:
Settlement proceeds receivable attributable to acquired Barnett Shale oil and gas property costs	858,422		—
(Decrease) increase in accrued purchases of property and equipment	112,398		(54,190)
Oil and natural gas property costs attributable to the recognition of asset retirement obligations	—		91,430

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Evolution Petroleum Corporation and Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements

Note 18 – Subsequent Events

On January 14, 2022, the Company completed the acquisition of non-operated oil and natural gas assets in the Williston Basin in North Dakota from Foundation Energy Fund VII-A, LP and Foundation Energy Management, LLC, for $25.9 million, net of preliminary purchase price adjustments which included operating cash flows received from the effective date of June 1, 2021 though the closing date. The transaction was funded with cash on hand and $16.0 million in borrowings under the Company’s existing senior credit facility.

On February 3, 2022, the Company declared a quarterly cash dividend of $0.10 per share of common stock to shareholders of record on March 15, 2022 and payable on March 31, 2022.

On February 7, 2022, the Company entered into the Ninth Amendment to the Senior Secured Credit Facility. This amendment modified the definition of utilization percentage related to the required hedging covenant such that for the purposes of determining the amount of future production to hedge, the utilization of the Senior Secured Credit Facility will be based on the calculated collateral value to the extent it exceeds the borrowing base then in effect. The amendment also requires the Company to enter into hedges for the next twelve months covering 25% of expected oil and gas production over that period.

On February 8, 2022, the Company entered into a definitive purchase agreement to acquire non-operated interests in the Jonah Field in Wyoming from Exaro Energy III, LLC for $29.4 million. The transaction has an effective date of February 1, 2022 and is expected to close on or about April 1, 2022.

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

Executive Overview

Liquidity and Capital Resources

Results of Operations

Critical Accounting Policies and Estimates

Commonly Used Terms

“Current quarter” refers to the three months ended December 31, 2021, the Company's second quarter of fiscal 2022.

“Prior quarter” refers to the three months ended September 30, 2021, the Company's first quarter of fiscal 2022.

“Year-ago quarter” refers to the three months ended December 31, 2020, the Company's second quarter of fiscal 2021.

Executive Overview

General

Evolution Petroleum Corporation is an oil and natural gas company focused on delivering a sustainable dividend yield to its stockholders through the ownership, management, and development of oil and natural gas properties. In support of that objective, the Company's long-term goal is to build a diversified portfolio of oil and natural gas assets primarily through acquisitions, while seeking opportunities to maintain and increase production through selective development, production enhancements, and other exploitation efforts on its properties.

On December 31, 2021, our producing assets consist of non-operated interests in the Delhi Holt-Bryant Unit in the Delhi field in Northeast Louisiana (“Delhi”); the Hamilton Dome field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir; interests in the Barnett Shale located in North Texas, a natural gas producing shale reservoir; and overriding royalty interests in four onshore central Texas wells.

On May 7, 2021, we acquired non-operated working interests in the Barnett Shale field (“the Barnett Shale Acquisition”), a natural gas producing shale reservoir consisting of approximately 21,000 net acres held by production across nine North Texas counties. The acreage has an average working interest of 17.3% and associated average revenue interest of 14.2%. At the time of the Barnett Shale Acquisition, approximately 90% of the wells acquired were operated by Blackbeard Operating LLC (“Blackbeard”), while the remaining 10% were operated by the seven other operators. After the close of the Barnett Shale Acquisition, Blackbeard announced the sale of its interest to Diversified Energy Company PLC (“Diversified Energy”), who is presently the operator of the assets.

Our interests in Delhi, a CO2 enhanced oil recovery project, field consist of a 23.9% working interest, with an associated 19.0% revenue interest and separate overriding royalty and mineral interests of 7.2% yielding a total net revenue interest of 26.2%. The field is operated by Denbury, a subsidiary of Denbury, Inc.

Our interests in the Hamilton Dome field, a secondary recovery field utilizing water injection wells to pressurize the reservoir, consist of 23.5% working interest, with an associated 19.7% revenue interest (inclusive of a small overriding royalty interest). The field is operated by Merit Energy Company (“Merit”), a private oil and natural gas company, who owns the vast majority of the remaining working interest in Hamilton Dome field.

On January 14, 2022 and subsequent to the end of the current quarter we acquired non-operated working interests in 73 producing wells in the Williston Basin with an average working interest of approximately 39% and average revenue interest of approximately 33% located on approximately 47,500 net acres (85% held by production) across Billings, Golden Valley, and McKenzie counties in North Dakota. The asset is operated by Foundation Energy Management, an established operator in the geographic region. The effective date of the transaction is June 1, 2021.

Highlights for our Second Quarter of Fiscal 2022 and Current Operations Update

•Generated net income of $6.8 million ($0.20 per diluted share) in the current quarter, an increase of 30.9% from the prior quarter net income of $5.2 million ($0.16 per diluted share);

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•Produced 4,957 net barrels of oil equivalent per day (“BOEPD”) during the current quarter, and recognized $22.3 million in oil, natural gas and natural gas liquids revenues;

•Funded all operations, development capital expenditures, and cash dividends out of operating cash flow;

•Declared a dividend payment of $0.10 per share, an increase of 33% over the prior quarter dividend of $0.075, payable on March 31, 2022;

•Subsequent to December 31, 2021, we closed on oil weighted, non-operated oil and natural gas assets in the Williston Basin for $25.9 million net of preliminary purchase price adjustments including operating cash flows from the effective date of June 1, 2021 through the close on January 14, 2022; and

•Entered into a definitive purchase agreement on February 8, 2022 to acquire non-operated interests in the Jonah Field in Wyoming from Exaro Energy III, LLC for $29.4 million. The transaction has an effective date of February 1, 2022 and is expected to close on or about April 1, 2022.

Overview

Expectations surrounding improved demand for oil and natural gas combined with restrained supply growth has stimulated a rise in oil and natural gas prices to averages of approximately $77.33 per barrel of oil and $4.75 per MMBtu of natural gas during the second fiscal quarter of 2022, recovering substantially from the severe commodity price decline in fiscal 2020 as a result of the COVID-19 pandemic . Worldwide factors such as global health pandemics, geopolitical factors, international trade disruptions and tariffs, macroeconomics, supply and demand, refining capacity, petrochemical production, and derivatives trading, among others, continue to influence prices for oil, natural gas, and NGLs. Local factors also influence prices for oil, natural gas, and NGLs and include increasing or decreasing production trends, quality differences, regulation, and transportation issues unique to certain producing regions and reservoirs.

Oil

Net oil production averaged approximately 1.6 MBOPD during the quarter, a 12.4% increase from the prior quarter primarily due to 0.2 MBOPD in production received from $1.1 million in past royalties that accumulated over a period of approximately three years, and are associated with overriding royalty interests we own in two wells located in the Giddings field in Burleson County, Texas. Also contributing to the increase was higher production at Hamilton Dome due to the restoration of previously shut-in wells and strategic adjustments to water injection locations and volumes. This increase was partially offset by lower Delhi oil production resulting from decreased reservoir pressure from suspension of new CO2 purchases in calendar year 2020 coupled with planned and unplanned compressor maintenance in November and December 2021 which temporarily reduced daily production. Reservoir pressure is gradually being restored with additional CO2 purchases from the Delta CO2 pipeline above the 85 MMcf per day baseline purchase average.

Natural Gas Liquids

Net natural gas liquids (“NGL”) production averaged approximately 18 BOEPD, a 99% decrease from the prior quarter. The decrease is attributable to the following: (i) changes in estimates in the current period related to prior periods for natural gas liquids volumes at our Barnett Shale assets resulting from the election of ethane rejection by the operator during the prior quarter and current quarter to maximize field cash flows; (ii) downtime at the Delhi NGL Plant in October 2021 to replace a turbine; and (iii) cold inlet temperatures at the Delhi NGL plant that reduced flow rates. Ethane rejection in the Barnett Shale is primarily a financial decision to capture the most favorable commodity prices resulting in higher natural gas volumes and lower NGL volumes while maximizing overall cash flow.

Natural Gas

Net natural gas production averaged approximately 19.8 MMCFPD during the quarter, a 24% increase from the prior quarter primarily due to ethane rejection in the Barnett Shale, as discussed above. Essentially all the Company’s natural gas production is generated from the Barnett Shale assets.

Net Income

We recorded quarterly net income of $6.8 million, or $0.20 per share, compared to $5.2 million, or $0.16 per share, in the prior quarter. The increase in net income is attributable to higher commodity prices, partially offset by lower production and higher operating expenses. The Company’s average realized price per barrel of oil increased 39.5% per BOE to $48.98 compared to $35.12 in the prior quarter. This increase was primarily due to the 36% increase in natural gas price from $3.70 per Mcf in the

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prior quarter to $5.03 per Mcf in the current quarter and the 6.3% increase in our average realized price per barrel of oil from $66.14 in the prior quarter to $70.29 in the current quarter.

Additional property and project information is included under Item 1. Business, Item 2. Properties, Notes to the Financial Statements and Exhibit 99.1 of our Form 10-K for the year ended June 30, 2021.

Full Cost Pool Ceiling Test and Impairment

At December 31, 2021, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling; however, we could experience an impairment if commodity price levels were to substantially decline. Lower commodity prices would reduce the excess, or cushion, of our valuation ceiling over our capitalized costs and may adversely impact our ceiling tests in future quarters. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required in the future.

Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion, and amortization (“DD&A”) and related deferred taxes, are limited to the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and natural gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average first day of the month price for our petroleum products during the 12-month period ending with the balance sheet date. The prices used in calculating our ceiling test at December 31, 2021 were $66.55 per barrel of oil, $3.64 per MMBtu of gas, and $26.54 per barrel of natural gas liquids. As of December 31, 2021, a 10% decrease in commodity prices used to determine our proved reserves would not have resulted in an impairment of our oil and natural gas properties.

Impact of the COVID-19 Pandemic and Geopolitical Factors

On March 11, 2020, the World Health Organization declared COVID-19 a pandemic, and on March 13, 2020, the United States of America declared a national emergency with respect to COVID-19. The virus has continued to spread in the United States of America and abroad. National, state, and local authorities continue to recommend social distancing, impose quarantine and isolation measures. Periodic business closures have impacted large portions of the population as the Delta and Omicron variants of COVID-19 emerged in the past twelve months. These measures, while intended to protect human life, are expected to have continued impacts on domestic and foreign economies, potentially resulting in volatility in commodity prices.

Currently, none of our property interests are operated by us. As a result, the Company has limited ability to influence or control the operation or future development of such properties. We continue to be proactive with its third-party operators to review spending and alter plans as appropriate.

We are focused on maintaining our operations and system of controls remotely and have implemented our business continuity plans in order to allow our employees to securely work from home and in the corporate office. We have been able to transition the operation of our business with minimal disruption and to maintain our system of internal controls and procedures.

Liquidity and Capital Resources

At December 31, 2021, the Company had $13.6 million in cash and cash equivalents, compared to $5.3 million of cash and cash equivalents at June 30, 2021. Working capital amounted to $22.0 million compared to $11.5 million at June 30, 2021, an increase of $10.5 million.

In addition, the Company has a senior secured reserve-based credit facility (the “Senior Secured Credit Facility”) with a maturity date of April 9, 2024. As of December 31, 2021, the Senior Secured Credit Facility had a $50 million borrowing base of which the Company has currently elected a maximum commitment amount of $40 million at this time, with $4.0 million outstanding. The Senior Secured Credit Facility is subject to a periodic redetermination by the lender based on the value of our oil and natural gas properties and is secured by substantially all of the reserves associated with the Company's assets.

Borrowings bear interest, at the Company's option, at either the LIBOR plus 2.75% or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%. The Senior Secured Credit Facility contains covenants requiring the maintenance of (i) a total leverage ratio of not more than 3.0 to 1.0, (ii) a current ratio of not less than 1.0 to 1.0, and (iii) a consolidated tangible net worth of not less than $40 million, each as defined in the Senior Secured Credit Facility. The Senior Secured Credit Facility also contains other customary affirmative and negative covenants and events of default. As of December 31, 2021, the Company was in compliance with all covenants contained in the Senior Secured Credit Facility.

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The Company has historically funded operations through cash from operations and working capital. The primary source of cash is the sale of produced oil, natural gas, and natural gas liquids. A portion of these cash flows is used to fund capital expenditures. The Company expects to manage future development activities in the Delhi field and the limited capital maintenance requirements of the Hamilton Dome field and Barnett Shale assets within the boundaries of its operating cash flow and existing working capital.

The Company is pursuing new growth opportunities through acquisitions and other transactions. In addition to cash on hand, the Company has access to the undrawn portion of the borrowing base available under its Senior Secured Credit Facility. The Company also has an effective shelf registration statement with the SEC under which the Company may issue up to $500 million of new debt or equity securities.

During the six months ended December 31, 2021, the Company funded operations, capital expenditures, and cash dividends with cash generated from operations. As of December 31, 2021, working capital was $22.0 million, an increase over working capital of $11.5 million at June 30, 2021. This increase in working capital is primarily due to the increase in production as a result of the closing of the Barnett Shale Acquisition in May 2021.

The Board of Directors instituted a quarterly cash dividend on common stock in December 2013, and has paid each consecutive quarter since. Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of the Company’s financial strategy, and it is the Company's long-term goal to increase dividends over time, as appropriate. As a result of the collapse in commodity prices during the industry downturn and global pandemic, effective in the quarter ended June 30, 2020, the Board of Directors adjusted the quarterly dividend rate from $0.10 per share to $0.025 per share. The reduction in the dividend rate at that time allowed the Company to conserve cash for additional financial flexibility while continuing to reward shareholders with a yield of approximately 3%. Considering improving Company financial performance and industry outlook, the Board of Directors has since increased the dividend rate with the most recent increase occurring on February 3, 2022, when the Board of Directors declared an increased dividend rate of $0.10 per share payable on March 31, 2022.

Subsequent to December 31, 2021, the Company closed the acquisition of interests in the Williston Basin. Funding for the acquisition was provided by cash on hand and a $16.0 million draw on the Company’s Senior Secured Credit Facility. After the close of the acquisition, the Company had $20.0 million remaining of borrowing capacity, not including any potential future increase in the borrowing base.

Capital Expenditures

For the six months ended December 31, 2021, we incurred $0.6 million primarily for Delhi field capital maintenance activities. Based on discussions with operators of the Company's assets, we expect to continue to perform conformance workover projects and will likely incur additional maintenance capital expenditures at the Delhi field. Additionally, based on discussions with the operator of the Barnett Shale, we anticipate to incur capital expenditures for workover projects as there are current plans to run one workover rig continuously throughout calendar year 2022. Based on discussions with the operators of our properties, we expect expenditures across the Barnett Shale, Hamilton Dome, and Delhi fields to be in the range of $0.5 million to $1.5 million during the remainder of fiscal 2022. Additionally, on January 14, 2022, the Company closed on the acquisition of Williston Basin assets and following discussions with the operator, we anticipate additional capital expenditures in the range of $0.5 to $1.0 million dollars during the remaining six months of fiscal 2022.

Our proved undeveloped reserves at June 30, 2021 included 1.81 MMBOE of reserves and approximately $8.6 million of future development costs associated with Phase V development in the eastern portion of the Delhi Field. Such development requires participation by both the operator and the Company. Based on our discussions with the operator, we do not expect drilling to commence prior to the second half of fiscal 2023. The timing of Phase V is dependent, in part, on the field operator's available funds and capital spending plans and priorities within its portfolio of properties.

Funding for our anticipated capital expenditures over the next 12 months is expected to be met from cash flows from operations, current working capital and draws on our credit facility as needed for future acquisitions.

Cash Flow Activities

Cash provided by operating activities in the current fiscal period increased $12.7 million compared to the same year-ago period primarily due to a $29.9 million increase in revenues and decrease in payments paid for derivative settlements of $2.1 million partially offset by a $13.9 million increase in field lease operating expenses with the inclusion of Barnett Shale assets. In addition, there was an increase of $0.6 million in general and administrative expenses primarily due to additional salary and benefits expense for new employees and professional fees associated with the recent increase in the Company’s acquisition activity, and a $1.6 million decrease in cash provided from changes in current operating assets and liabilities. The decrease in cash provided from changes in current operating assets and liabilities is primarily driven by a lag in revenue receipts and monthly invoices from the operator of the Barnett Shale assets. Revenue settlement statements from the operator of the Barnett

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Shale assets and the related cash consideration are generally distributed to the Company two months after production has occurred, which is typical in the oil and gas industry. Diversified Energy recently acquired the interests and took over as operator of the Barnett Shale assets from Blackbeard. Transition of the operator from Blackbeard to Diversified has caused timing delays in the receipt of revenue and lease operating statements, and as a result, the current fiscal quarter includes impacts from changes in estimates related to prior periods for the Barnett Shale assets. Additionally, the current fiscal period includes a receivable for expected cash related to the post-closing settlement statement for the Barnett Shale Acquisition, a portion of which impacted cash provided from changes in current operating assets and liabilities.

Cash used in investing activities increased $0.3 million primarily due to resumed development costs in the Delhi field after Denbury's emergence from bankruptcy in the prior fiscal year.

Cash used in financing activities increased $3.4 million primarily due to an increase in common stock dividends paid in the current period as the dividend rate was increased by the Board of Directors to $0.075 per share compared to $0.025 in the same year-ago period.

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Results of Operations

Three Months Ended December 31, 2021 and 2020

Revenues

Compared to the year-ago quarter, current quarter revenues increased 287.3% primarily due to the Barnett Shale Acquisition and $1.1 million received for past royalties that accumulated over a period of approximately three years, coupled with a 40.5% increase in the Company's realized equivalent price per BOE. The 175.7% increase in production was primarily due to the Barnett Shale Acquisition.

The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the three months ended December 31, 2021 and 2020:


	Three Months Ended December 31,
	2021		2020		Variance		Variance %
Oil and gas production
Revenues
Oil	$	10,582,145	$	5,462,783	$	5,119,362	93.7	%
Natural gas liquids (a)	2,586,758		305,200		2,281,558		747.6	%
Natural gas (b)	9,169,458		169		9,169,289		n.m.
Total revenues	$	22,338,361	$	5,768,152	$	16,570,209	287.3	%

Production Volumes
Oil (Bbl)	150,551		140,700		9,851		7.0	%
Natural gas liquids (Bbl) (a)	1,643		24,695		(23,052)		(93.3)	%
Natural gas (Mcf) (b)	1,823,084		85		1,822,999		n.m.
Equivalent (BOE)	456,041		165,409		290,632		175.7	%

Daily Production Volumes
Oil (BOPD, net)	1,636		1,529		107		7.0	%
Natural gas liquids (BOEPD, net) (a)	18		268		(250)		(93.3)	%
Natural gas (BOEPD, net) (b)	3,303		—		3,303		n.m.
Equivalent volumes (BOEPD, net)	4,957		1,797		3,160		175.8	%

Realized Prices
Oil price per Bbl	$	70.29	$	38.83	$	31.46	81.0	%
Natural gas liquids price per Bbl (a)	1,574.41		12.36		1,562.05		12,637.9	%
Natural gas price per Mcf (b)	5.03		1.99		3.04		n.m.
Equivalent price per BOE	$	48.98	$	34.87	$	14.11	40.5	%

n.m. not meaningful.

(a) A volume reduction in the Barnett Shale due to changes in estimates in the current period that were related to prior periods adversely impacted the natural gas liquids results for the quarter. These changes were the result of the Barnett field operator’s decision to reject ethane. This adjustment reduced NGL revenue by $1.1 million and NGL volumes by 88 MBbls thereby affecting related metrics. Excluding these adjustments, the realized NGL price per Bbl for the three months ended December 31, 2021 would have been $41.25.

(b) The aforementioned changes in estimates in the Barnett Shale as a result of the operator’s election to reject ethane caused natural gas results to be positively impacted during the quarter. This adjustment increased natural gas revenue by $0.7 million and natural gas production by 304 MMcf thereby affecting the related metrics. Excluding these adjustments, the realized natural gas price per Mcf for the three months ended December 31, 2021 would have been $5.55.

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Derivative Contracts

Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in crude oil prices. This amount represents the (i) (gain) loss 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. There were no outstanding positions as of December 31, 2021.


	Three Months Ended December 31,
	2021		2020		Variance		Variance %
Oil Derivative Contracts
Realized loss on derivatives, net	$	—	$	1,374,412	$	(1,374,412)	100.0	%
Unrealized gain on derivatives	—		(1,094,733)		1,094,733		100.0	%
Net loss on derivatives contracts	$	—	$	279,679	$	(279,679)	100.0	%

Oil price per Bbl (including impact of realized derivatives)	$	70.29	$	29.06

Lease Operating Costs

Lease operating costs are presented in two components: (i) CO2 costs for the Delhi field and (ii) other lease operating costs for the Delhi, Hamilton Dome, and Barnett Shale assets.


	Three Months Ended December 31,
	2021		2020		Variance		Variance %
CO2 costs (a)	$	1,897,374	$	619,887	$	1,277,487	206.1	%
Other lease operating costs	8,773,600		2,385,526		6,388,074		267.8	%
Total lease operating costs	$	10,670,974	$	3,005,413	$	7,665,561	255.1	%

CO2 costs per BOE	$	4.16	$	3.75	$	0.41	10.9	%
All other lease operating costs per BOE	19.24		14.42		4.82		33.4	%
Lease operating costs per BOE (b)	$	23.40	$	18.17	$	5.23	28.8	%

(a) 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.

(b) Increase in lease operating costs per BOE is due to increased CO2 purchases compared to the year-ago quarter when CO2 purchases were curtailed for part of the quarter.


	Three Months Ended December 31,
	2021		2020		Variance		Variance %
CO2 costs per mcf	$	0.92	$	0.55	$	0.37	67.3	%
CO2 volumes (MMcf per day, gross)	94.3		51.4		42.9		83.5	%

Compared to the year-ago quarter, CO2 costs increased $1.3 million. The increase in cost is due to a full quarter of purchases over the baseline 85 MMcf per day in the current quarter compared to fewer days of purchases at a lower rate the year-ago quarter together with an increase in WTI pricing. CO2 purchases historically provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%.

Compared to the year-ago quarter, "Other lease operating costs" increased by $6.4 million attributable to acquisition of the Barnett Shale and associated expenses, increased field work and workover activity at Hamilton Dome due to favorable economics, higher labor and NGL plant costs resulting from unplanned downtime, and the increased cost for fuel and power across all Company assets.

On a total cost per BOE basis, Delhi costs increased 129.6% to $35.32 per BOE in the current quarter, primarily due to a 206.1% increase in CO2 cost per BOE from higher realized oil prices as well as a 38.9% increase in other lease operating costs per BOE from the year-ago quarter due to the resumption of workover projects.

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Hamilton Dome field costs per BOE increased by $10.26 to $38.88 in the current quarter due to an increase in workover activity.

Barnett Shale field costs per BOE were $18.79 in the current quarter. These costs were negatively impacted by the changes in estimates in the current period that were related to prior periods as a result of the operator’s election to reject ethane. Excluding these adjustments the Barnett field costs per BOE would have been $15.99 in the current quarter.

Depletion, Depreciation, and Amortization ("DD&A")

Total DD&A expense was 9.9% lower compared to the same year-ago quarter due to a 14.6% decrease in the oil and natural gas DD&A amortization. The Company's oil and natural gas DD&A rate decreased 69.0% on a per BOE basis primarily as result of the full cost ceiling test impairment recorded during the prior fiscal year and the Barnett Shale Acquisition which lowered the overall amortizable base on a per unit basis.


	Three Months Ended December 31,
	2021		2020		Variance		Variance %
DD&A of proved oil and natural gas properties	$	1,118,204	$	1,308,716	$	(190,512)	(14.6)	%
Depreciation of other property and equipment	2,818		1,810		1,008		55.7	%
Amortization of intangibles	—		3,391		(3,391)		(100.0)	%
Accretion of asset retirement obligations	102,699		44,251		58,448		132.1	%
Total DD&A	$	1,223,721	$	1,358,168	$	(134,447)	(9.9)	%

Oil and natural gas DD&A rate per BOE	$	2.45	$	7.91	$	(5.46)	(69.0)	%

Proved Property Impairment

The Company utilizes the full cost method of accounting for its oil and gas properties. Under this method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties included in the amortization base, plus the cost of unproved properties excluded from amortization, as adjusted for related income tax effects (the valuation “ceiling”). The prices used in calculating our ceiling test at December 31, 2021 were $66.55 per barrel of oil, $3.64 per MMBtu of gas, and $26.54 per barrel of natural gas liquids compared to $57.64 per barrel of oil, $2.97 per MMBtu of gas, and $23.04 per barrel of natural gas liquids at September 30, 2021. There was no proved property impairment recorded in the quarter ended December 31, 2021. The company recorded a proved property impairment of $15.2 million during the year-ago quarter primarily as a result of the prices used in the ceiling test of $39.54 per barrel of oil and $8.30 per barrel of natural gas liquids at December 31, 2020 (there were no natural gas reserves during the year-ago quarter).

General and Administrative Expenses

For the three months ended December 31, 2021, expenses of $1.8 million was essentially flat compared to the year-ago quarter. A $0.2 million decrease in salary, benefits and incentive compensation cost was offset by higher investor relations expense associated with the Company’s inaugural Corporate Sustainability Report and increased professional fees impacted by acquisition activities.

Other Income and Expenses

Other income and expense (net) decreased primarily due to increased interest expense from our outstanding borrowings on the Senior Secured Credit Facility.


	Three Months Ended December 31,
	2021		2020		Variance		Variance %
Interest and other income	7,293		11,217		(3,924)		(35.0)	%
Interest expense	(50,930)		(19,622)		(31,308)		159.6	%
Total other income (expense), net	$	(43,637)	$	(8,405)	$	(35,232)	419.2	%

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Net Income (Loss)

Net income (loss) attributable to common stockholders for the three months ended December 31, 2021 increased $19.5 million to $6.8 million compared to the same year-ago quarter. Pre-tax income increased due to the aforementioned revenue and expense variances. Our income tax provision increased primarily due to higher pre-tax income as well as a slight increase in our effective tax rate.


	Three Months Ended December 31,
	2021			2020			Variance		Variance %
Income (loss) before income taxes	$	8,576,784		$	(15,918,671)		$	24,495,455	(153.9)	%
Income tax expense (benefit)	$	1,744,612		$	(3,208,664)		$	4,953,276	(154.4)	%
Net income (loss) attributable to common stockholders	$	6,832,172		$	(12,710,007)		$	19,542,179	(153.8)	%
Income tax provision (benefit) as percentage of income (loss) before income taxes	20.3		%	20.2		%

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Results of Operations

Six Months Ended December 31, 2021 and 2020

Revenues

Compared to the six months ended December 31, 2020, current corresponding period revenues increased 263% primarily due to the acquisition of the Barnett Shale assets and $1.1 million received for past royalties that accumulated over a period of approximately three years, together with a 22% increase in the Company’s realized equivalent price per BOE. The natural decline of the Delhi field has been temporarily increased by the shut-in of the CO2 supply pipeline from late February through the end of October 2020 as discussed in "Lease Operating Costs" below, as well as a suspension of field conformance capital expenditures from Spring 2019 through Spring 2021. Purchased CO2 is necessary to maintain reservoir pressure and therefore achieve normal field performance. The shut-in of purchased volumes resulted in a decline in reservoir pressure and the temporarily increased production decline. The resumption of CO2 purchases, with an increase in nominations over the baseline prior to the shut-in, during the current period is expected to gradually restore reservoir pressure, arrest production decline, and lead to a gradual increase in oil production. The Company’s average realized oil price was higher primarily due to the recovery of WTI pricing. The Company’s Hamilton Dome production typically trades at a discount to WTI due to its specific gravity and sulfur content. The Company’s Barnett Shale natural gas production has been trading through Houston Ship Channel index less a discount for transportation and marketing.

The following table summarizes total oil, natural gas, and NGL revenues, production volumes, daily production volumes, average realized prices for the six months ended December 31, 2021 and 2020:


	Six Months Ended December 31,
	2021			2020		Variance		Variance %
Oil and gas production
Revenues
Oil	$	19,440,608		$	10,841,944	$	8,598,664	79.3	%
Natural gas liquids	7,148,976			521,226		6,627,750		1,271.6	%
Natural gas	14,627,787			358		14,627,429		n.m.
Total revenues	$	41,217,371		$	11,363,528	$	29,853,843	262.7	%

Production volumes
Oil (Bbl)	284,480			286,357		(1,877)		(0.7)	%
Natural gas liquids (Bbl)	159,236			48,419		110,817		228.9	%
Natural gas (Mcf)	3,299,303			215		3,299,088		n.m.
Equivalent (BOE)	993,600			334,812		658,788		196.8	%

Daily production volumes
Oil (BOPD, net)	3,092			1,556		1,536		98.7	%
Natural gas liquids (BOEPD, net)	1,731			263		1,468		558.2	%
Natural gas (BOEPD, net)	5,977			—		5,977		n.m
Equivalent volumes (BOEPD, net)	10,800			1,819		8,981		493.7	%

Realized prices
Oil price per Bbl	$	68.34		$	37.86	$	30.48	80.5	%
Natural gas liquids price per Bbl	44.90			10.76		34.14		317.3	%
Natural gas price per Mcf	4.43			1.67		2.76		165.3	%
Equivalent price per BOE	$	41.48	(a)	$	33.94	$	7.54	22.2	%

n.m. not meaningful.

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(a) Equivalent price per BOE has increased only 22% in the current six-month period despite an 81% increase in oil price per Bbl, a 317% increase in NGL price per Bbl, and a 165% increase in natural gas per Mcf. With the Barnett Shale Acquisition, the Company added significant natural gas and natural gas liquids sales compared to the same year-ago period. Natural gas and natural gas liquids sales are realized at a significantly lower price per BOE than oil which has resulted in only a slight increase in the Company's total weighted average price per BOE.

Derivative Contracts

Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil prices. The amounts recorded on the unaudited consolidated condensed 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. No positions remain outstanding as of December 31, 2021.


	Six Months Ended December 31,
	2021		2020		Variance		Variance %
Oil Derivative Contracts
Realized loss on derivatives, net	$	—	$	2,525,988	$	(2,525,988)	(100.0)	%
Unrealized gain on derivatives	—		(1,911,343)		1,911,343		(100.0)	%
Net loss on derivatives contracts	$	—	$	614,645	$	(614,645)	(100.0)	%

Oil price per Bbl (including impact of realized derivatives)	$	68.34	$	29.04

Lease Operating Costs

Lease operating costs (also referred to as production expenses) are presented in two components: (i) CO2 purchase costs for the Delhi field and (ii) other lease operating costs for the Delhi, Hamilton Dome, and Barnett Shale fields.


	Six Months Ended December 31,
	2021		2020		Variance		Variance %
CO2 costs (a)	$	2,814,423	$	619,887	$	2,194,536	354.0	%
Other lease operating costs	16,481,718		4,783,450		11,698,268		244.6	%
Total lease operating costs	$	19,296,141	$	5,403,337	$	13,892,804	257.1	%

CO2 costs per BOE	$	2.83	$	1.85	$	0.98	53.0	%
All other lease operating costs per BOE	16.59		14.29		2.30		16.1	%
Lease operating costs per BOE (b)	$	19.42	$	16.14	$	3.28	20.3	%

(a) 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.

(b) Increase in lease operating costs per BOE is due to increased CO2 purchases compared to the year-ago period when CO2 purchases were curtailed for part of the period.


	Six Months Ended December 31,
	2021		2020		Variance		Variance %
CO2 costs per mcf	$	0.89	$	0.55	$	0.34	61.8	%
CO2 volumes (MMcf per day, gross)	71.7		17.0		54.7		321.8	%

CO2, costs, which solely reflect the cost of purchased CO2 volumes, increased in the current six-month period compared to the year-ago period as CO2 purchases were temporarily suspended throughout the first quarter of fiscal 2021 due to a detected pressure loss in the pipeline that supplies newly purchased CO2 to the Delhi field. CO2 purchases historically provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. During the current six-month period, purchases from the pipeline were temporarily suspended from July 15th through August 20th, 2021,

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while the operator performed preventative maintenance on the pipeline. The pipeline is owned and operated by Denbury, and we do not have any ownership in the pipeline which is upstream of the Delhi field.

Compared to the six months ended December 31, 2020, “Other lease operating costs” increased by $11.7 million primarily due to the Barnett Shale Acquisition on May 7, 2021. The Delhi and Hamilton Dome field’s “Other lease operating costs” were $0.6 million and $1.0 million higher, respectively, compared to the corresponding year-ago period primarily due to higher workover, labor, and chemical expenses.

Delhi field costs per BOE increased 109% to $28.19 per BOE, primarily due to the increase in CO2 costs compared to the year-ago period which had limited CO2 costs from the purchase pipeline being shut-in. Additionally, other lease operating costs per BOE increased by 41% due to higher electricity costs, unplanned downtime at the NGL plant, and higher purchased fuel gas costs. Also contributing to the increase on a per BOE basis is the 14% decrease in net production volumes in the Delhi field from the year-ago period as a result of natural decline and reduced field pressure from the lower CO2 injections when the CO2 pipeline was taken offline.

Hamilton Dome field costs per BOE increased 45% to $37.57 per BOE in the current period as a result of several factors. Higher commodity prices have provided the operator with incentive to perform prior year deferred maintenance and expense workovers that were deemed uneconomic in the year-ago period. Accordingly, workover expense has increased 241% compared to the year-ago period. This level of workover expense is expected to decline in future quarters. Compared to the year-ago period, the increase in commodity prices has also resulted in increased in electricity, fuel cost, ad valorem tax and production tax expenses.

Barnett Shale lease operating costs were $15.10 per BOE in the current period.

Depletion, Depreciation, and Amortization (“DD&A”)

Total DD&A expense was 1% higher compared to the same year-ago period primarily due to the increase in production from the Barnett Shale assets acquired on May 7, 2021. The Company’s oil and natural gas DD&A rate per BOE decreased 68% compared to the year-ago period primarily as a result of proved oil and natural gas property impairments recorded in fiscal year 2021 and and the Barnett Shale Acquisition which lowered the overall amortizable base on a per unit basis.


	Six Months Ended December 31,
	2021		2020		Variance		Variance %
DD&A of proved oil and natural gas properties	$	2,544,072	$	2,670,801	$	(126,729)	(4.7)	%
Depreciation of other property and equipment	3,902		3,620		282		7.8	%
Amortization of intangibles	—		6,782		(6,782)		(100.0)	%
Accretion of asset retirement obligations	203,559		87,853		115,706		131.7	%
Total DD&A	$	2,751,533	$	2,769,056	$	(17,523)	(0.6)	%

Oil and natural gas DD&A rate per BOE	$	2.56	$	7.98	$	(5.42)	(67.9)	%

Proved Property Impairment

The Company utilizes the full cost method of accounting for its oil and gas properties. Under this method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties included in the amortization base, plus the cost of unproved properties excluded from amortization, as adjusted for related income tax effects (the valuation “ceiling”). There was no proved property impairment recorded in the six months ended December 31, 2021. The prices used in calculating our ceiling test at December 31, 2021 were $66.55 per barrel of oil, $3.64 per MMBtu of gas, and $26.54 per barrel of natural gas liquids compared to $57.64 per barrel of oil, $2.97 per MMBtu of gas, and $23.04 per barrel of natural gas liquids used in our ceiling test at September 30, 2021. The company recorded proved property impairments totaling of $24.8 million during the six months ended December 31, 2020 primarily as a result of the prices used in the ceiling test of $39.54 per barrel of oil and $8.30 per barrel of natural gas liquids at December 31, 2020 and $43.63 per barrel of oil and $7.85 per barrel of natural gas liquids at September 30, 2020. There were no natural gas reserves then.

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General and Administrative Expenses

For the six months ended December 31, 2021, general and administrative expenses increased $0.6 million to $3.8 million compared to the corresponding year-ago period primarily due to additional salary and benefits expense for new employees, professional fees associated with acquisition activity and some one-time costs associated with the development of the Company’s inaugural Corporate Sustainability Report including a new website and branded matching Investor Relations materials.

Other Income and Expenses

Other income and expense (net) decreased due primarily to increased interest expense from our outstanding borrowings on the Senior Secured Credit Facility.


	Six Months Ended December 31,
	2021		2020		Variance		Variance %
Interest and other income	$	9,770	$	25,643	$	(15,873)	(61.9)	%
Interest expense	(101,542)		(41,654)		(59,888)		143.8	%
Total other income (expense), net	$	(91,772)	$	(16,011)	$	(75,761)	473.2	%

Net Income (Loss)

Net income (loss) attributable to common stockholders for the six months ended December 31, 2021 increased $31.9 million to $12.1 million compared to the same year-ago period. Pre-tax income increased due to the aforementioned revenue and expense variances. Our income tax expense increased primarily due to an increase in estimated pre-tax income for the current fiscal year as compared to a pre-tax loss for the prior year period.


	Six Months Ended December 31,
	2021			2020			Variance		Variance %
Income (loss) before income taxes	$	15,314,771		$	(25,355,997)		$	40,670,768	(160.4)	%
Income tax expense (benefit)	3,264,198			(5,510,842)			8,775,040		(159.2)	%
Net income (loss) attributable to common stockholders	$	12,050,573		$	(19,845,155)		$	31,895,728	(160.7)	%
Income tax expense (benefit) as percentage of income (loss) before income taxes	21.3		%	21.7		%

Critical Accounting Policies and Estimates

See our Critical Accounting Policies and Estimates as disclosed within Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in the 2021 Form 10-K. For recently adopted and recently issued accounting pronouncements from the Financial Accounting Standards Board, please see Note 2 – Summary of Significant Accounting Policies herein.

Item 3. Quantitative and Qualitative Disclosures About Market Risks

Information about market risks for the three months ended December 31, 2021, did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended June 30, 2021.

Interest Rate Risk

We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents. Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes.

Item 4. Controls and Procedures

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

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As required by SEC Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief 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)) 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 Executive Officer and Chief Financial Officer concluded that as of December 31, 2021 our disclosure controls and procedures are effective in ensuring that the information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms.

Under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer, during the quarter ended December 31, 2021, we have determined there have been no changes in our internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

None.

Item 1A. Risk Factors

Our Annual Report on Form 10-K for the year ended June 30, 2021 includes a detailed description of our risk factors.

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

Issuer Purchases of Equity Securities

During the quarter ended December 31, 2021, the Company did not purchase any common stock in the open market under a previously announced share repurchase program and no shares of common stock were surrendered by its employees to pay their share of payroll taxes arising from vesting of restricted stock.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

A. Exhibits

31.1

Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.

31.2

Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.

32.1

Certification of Chief Executive Officer pursuant to18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS

Inline XBRL Instance Document

101.SCH

Inline XBRL Taxonomy Extension Schema Document

101.CAL

Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF

Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB

Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE

Inline XBRL Taxonomy Extension Presentation Linkbase Document

104

Cover Page Interactive Data File (embedded within the Inline XBRL document)

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SIGNATURES

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

EVOLUTION PETROLEUM CORPORATION

(Registrant)


	By:	/s/ Jason E. Brown
		Jason E. Brown
		President and Chief Executive Officer

Date: February 10, 2022