Table of Contents


no

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

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

For the quarterly period ended DecemberMarch 31, 2017

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
2024

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

For the transition period from                to

Commission File Number 001-32942

EVOLUTION PETROLEUM CORPORATION

CORPORATION

(Exact name of registrant as specified in its charter)


Graphic

Nevada

41-1781991

Nevada41-1781991

(State or other jurisdiction of
incorporation or organization)

(IRS Employer

Identification No.)

1155 Dairy Ashford Road, Suite 425, Houston, Texas77079

(Address of principal executive offices and zip code)

(713)

(713935-0122

(Registrant’s telephone number, including area code)

Not Applicable
(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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). 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 definitionsdefinition of “large"large accelerated filer,” “accelerated filer,” “smallerfiler", "accelerated filer", "smaller reporting company,”company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer o

Accelerated filerx

Non-accelerated filer

Smaller reporting company  

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

     Smaller reporting company o

Emerging growth companyo

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


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

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


The number of

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

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


EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES


TABLE OF CONTENTS

Page
2

Forward-Looking Statements

2

.

4

Item 1.

Condensed Consolidated Financial Statements (Unaudited)

4

4

5

6

7

8

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

25

40

Item 4.

Controls and Procedures

40

41

Item 1.

Legal Proceedings

41

41

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

41

42

Item 4.

Mine Safety Disclosures

42

42

Item 6.

Exhibits

42

43




PART I — FINANCIAL INFORMATION
ITEM 1. CONSOLIDATEDCONDENSEDFINANCIAL STATEMENTS

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

Consolidated Condensed Balance Sheets

1

(Unaudited)


 December 31,
2017
 June 30,
2017
Assets 
  
Current assets 
  
Cash and cash equivalents$25,743,497
 $23,028,153
Receivables4,078,153
 2,726,702
Prepaid expenses and other current assets824,048
 387,672
Total current assets30,645,698
 26,142,527
Oil and natural gas property and equipment, net (full-cost method of accounting)60,093,807
 61,790,068
Other property and equipment, net32,265
 40,689
Total property and equipment60,126,072
 61,830,757
Other assets260,468
 295,384
Total assets$91,032,238
 $88,268,668
Liabilities and Stockholders’ Equity 
  
Current liabilities 
  
Accounts payable$2,400,202
 $1,994,255
Accrued liabilities and other660,467
 724,639
Total current liabilities3,060,669
 2,718,894
Long term liabilities 
  
Deferred income taxes10,580,381
 15,826,291
Asset retirement obligations1,297,028
 1,253,628
Total liabilities14,938,078
 19,798,813
Commitments and contingencies (Note 14)

 

Stockholders’ equity 
  
Common stock; par value $0.001; 100,000,000 shares authorized; 33,171,514 and 33,087,308 shares issued and outstanding as of December 31, 2017 and June 30, 2017, respectively33,171
 33,087
Additional paid-in capital41,538,133
 40,961,957
Retained earnings34,522,856
 27,474,811
Total stockholders’ equity76,094,160
 68,469,855
Total liabilities and stockholders’ equity$91,032,238
 $88,268,668

Table of Contents


FORWARD-LOOKING STATEMENTS

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

our expectations of plans, strategies and objectives, including anticipated development activity and capital spending;
our capital allocation strategy, capital structure, anticipated sources of funding, growth in long-term shareholder value and ability to preserve balance sheet strength;
the benefits of our multi-basin portfolio, including operational and commodity flexibility;
our ability to maximize cash flow and the application of excess cash flows to reduce long-term debt, pay dividends and repurchase shares pursuant to our share repurchase program;
estimates of our oil, natural gas and natural gas liquids (“NGLs”) production and commodity mix;
anticipated oil, natural gas and NGL prices;
anticipated drilling and completions activity;
estimates of our oil, natural gas and NGL reserves and recoverable quantities;
our ability to access credit facilities and other sources of liquidity to meet financial obligations throughout commodity price cycles;
limitations on our ability to obtain funding based on environmental, social, and corporate governance (“ESG”) performance;
future interest expense;
our ability to manage debt and financial ratios, finance growth and comply with financial covenants;
the implementation and outcomes of risk management programs, including exposure to commodity price and interest rate fluctuations, the volume of oil and natural gas production hedged, and the markets or physical sales locations hedged;
the impact of changes in federal, state, provincial and local, rules and regulations;
anticipated compliance with current or proposed environmental requirements, including the costs thereof;
the possible impact of greenhouse gas (“GHG”) emissions limitations and renewable energy incentives;
adequacy of provisions for abandonment and site reclamation costs;
our operational and financial flexibility, discipline and ability to respond to evolving market conditions;
the declaration and payment of future dividends and any anticipated repurchase of our outstanding common shares;
the adequacy of our provision for taxes and legal claims;
our ability to manage cost inflation and expected cost structures, including expected operating, transportation, processing and labor expenses;
our competitiveness relative to our peers, including with respect to capital, materials, people, assets and production;
oil, natural gas and NGL inventories and global demand for oil, natural gas and NGLs;
the outlook of the oil and natural gas industry generally, including impacts from changes to the geopolitical environment;
adverse weather events;
anticipated staffing levels;
anticipated payments related to our commitments, obligations and contingencies, and the ability to satisfy the same; and
the possible impact of accounting and tax pronouncements, rule changes and standards.

2

Table of Contents

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

future commodity prices and basis differentials;
our ability to access credit facilities and shelf prospectuses;
assumptions contained in our corporate guidance;
the availability of attractive commodity or financial hedges and the enforceability of risk management programs;
expectations that counterparties will fulfill their obligations pursuant to gathering, processing, transportation and marketing agreements;
access to adequate gathering, transportation, processing and storage facilities;
assumed tax, royalty and regulatory regimes;
expectations and projections made in light of, and generally consistent with, our historical experience and our perception of historical industry trends; and
the other assumptions contained herein.

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

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

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

3

Table of Contents

Part I. FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

EVOLUTION PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share amounts)

    

March 31, 2024

    

June 30, 2023

Assets

 

 

Current assets

 

 

Cash and cash equivalents

$

3,067

$

11,034

Receivables from crude oil, natural gas, and natural gas liquids revenues

13,368

7,884

Derivative contract assets

347

Prepaid expenses and other current assets

6,275

2,277

Total current assets

23,057

21,195

Property and equipment, net of depletion, depreciation, and impairment

 

Oil and natural gas properties, net—full-cost method of accounting, of which none were excluded from amortization

142,157

105,781

Other assets

1,318

1,341

Total assets

$

166,532

$

128,317

Liabilities and Stockholders' Equity

 

Current liabilities

 

Accounts payable

$

8,096

$

5,891

Accrued liabilities and other

5,985

6,027

Derivative contract liabilities

1,410

State and federal taxes payable

365

Total current liabilities

15,491

12,283

Long term liabilities

 

Senior secured credit facility

42,500

Deferred income taxes

6,927

6,803

Asset retirement obligations

18,079

17,012

Operating lease liability

79

125

Total liabilities

83,076

36,223

Commitments and contingencies (Note 10)

Stockholders' equity

 

Common stock; par value $0.001; 100,000,000 shares authorized: issued and

outstanding 33,359,854 and 33,247,523 shares as of March 31, 2024

and June 30, 2023, respectively

33

33

Additional paid-in capital

40,652

40,098

Retained earnings

42,771

51,963

Total stockholders' equity

83,456

92,094

Total liabilities and stockholders' equity

$

166,532

$

128,317

See accompanying notes to unaudited condensed consolidated condensed financial statements.


4

Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statements of Operations
(Unaudited)

Table of Contents

 Three Months Ended 
 December 31,
 Six Months Ended 
 December 31,
 2017 2016 2017 2016
Revenues 
  
  
  
Crude oil$10,185,635
 $8,529,817
 $18,014,890
 $16,123,672
Natural gas liquids881,276
 
 1,589,892
 89
Natural gas
 
 
 (4)
     Total revenues11,066,911
 8,529,817
 19,604,782
 16,123,757
Operating costs       
Production costs2,914,512
 2,292,421
 5,806,098
 4,637,062
Depreciation, depletion and amortization1,633,868
 1,307,510
 3,152,411
 2,580,949
Accretion of discount on asset retirement obligations23,023
 13,106
 44,602
 26,330
General and administrative expenses *1,666,256
 1,241,399
 3,235,960
 2,476,442
Total operating costs6,237,659
 4,854,436
 12,239,071
 9,720,783
Income from operations4,829,252
 3,675,381
 7,365,711
 6,402,974
Other 
  
  
  
Gain on realized derivative instruments, net
 
 
 90
Loss on unrealized derivative instruments, net
 
 
 (14,132)
Interest and other income15,841
 14,061
 30,691
 26,806
Interest expense(20,456) (20,711) (40,911) (41,056)
Income before income taxes4,824,637
 3,668,731
 7,355,491
 6,374,682
Income tax provision (benefit)(5,052,211) 1,361,097
 (4,661,889) 2,250,273
Net income attributable to the Company9,876,848
 2,307,634
 12,017,380
 4,124,409
Dividends on preferred stock
 
 
 250,990
Deemed dividend on redeemed preferred shares
 
 
 1,002,440
Net income available to common stockholders$9,876,848
 $2,307,634
 $12,017,380
 $2,870,979
Earnings per common share       
Basic$0.30
 $0.07
 $0.36
 $0.09
Diluted$0.30
 $0.07
 $0.36
 $0.09
Weighted average number of common shares 
  
  
  
Basic33,109,448
 33,047,166
 33,099,546
 33,002,088
Diluted33,140,278
 33,083,027
 33,140,257
 33,037,269
* General and administrative expenses for the three months ended December 31, 2017 and 2016 included non-cash stock-based compensation expense of $484,326 and $275,184, respectively. For the corresponding six month periods, non-cash stock-based compensation expense was $971,810 and $586,872, respectively.

Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statements of Cash Flows

EVOLUTION PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

 Six Months Ended 
 December 31,
 2017 2016
Cash flows from operating activities 
  
Net income attributable to the Company$12,017,380
 $4,124,409
Adjustments to reconcile net income to net cash provided by operating activities: 
  
Depreciation, depletion and amortization3,180,545
 2,609,356
Stock-based compensation971,810
 586,872
Accretion of discount on asset retirement obligations44,602
 26,330
Settlements of asset retirement obligations
 (121,391)
Deferred income taxes (benefit)(5,245,910) 1,709,519
Loss on derivative instruments, net
 14,042
Changes in operating assets and liabilities: 
  
Receivables(1,351,451) (462,981)
Prepaid expenses and other current assets(436,376) (367,039)
Accounts payable and accrued expenses(83,013) (1,955,546)
Income taxes payable
 (311,306)
Net cash provided by operating activities9,097,587
 5,852,265
Cash flows from investing activities 
  
Derivative settlement payments paid
 (318,618)
Capital expenditures for oil and natural gas properties(1,017,358) (7,978,130)
Capital expenditures for other property and equipment
 (30,447)
Net cash used in investing activities(1,017,358) (8,327,195)
Cash flows from financing activities 
  
Cash dividends to preferred stockholders
 (250,990)
Cash dividends to common stockholders(4,969,335) (3,801,962)
Common share repurchases, including shares surrendered for tax withholding(395,550) (459,858)
Redemption of preferred shares
 (7,932,975)
Other
 32
Net cash used in financing activities(5,364,885) (12,445,753)
Net increase (decrease) in cash and cash equivalents2,715,344
 (14,920,683)
Cash and cash equivalents, beginning of period23,028,153
 34,077,060
Cash and cash equivalents, end of period$25,743,497
 $19,156,377

Supplemental disclosures of cash flow information:Six Months Ended 
 December 31,
 2017 2016
Income taxes paid$1,136,754
 $1,278,773
Non-cash transactions: 
  
Change in accounts payable used to acquire property and equipment424,365
 (1,516,932)
Oil and natural gas property costs incurred through recognition of asset retirement obligations(779) 

(In thousands, except per share amounts)

 

Three Months Ended

Nine Months Ended

March 31, 

March 31, 

 

2024

2023

2024

    

2023

Revenues

Crude oil

$

14,538

$

11,799

$

38,913

$

40,062

Natural gas

5,860

21,598

17,943

58,816

Natural gas liquids

2,627

3,470

7,794

11,462

Total revenues

23,025

36,867

64,650

110,340

Operating costs

 

 

 

Lease operating costs

12,624

13,570

36,865

47,727

Depletion, depreciation, and accretion

5,900

3,383

14,760

10,439

General and administrative expenses

2,417

2,267

7,522

7,320

Total operating costs

20,941

19,220

59,147

65,486

Income (loss) from operations

2,084

17,647

5,503

44,854

Other income (expense)

 

 

 

Net gain (loss) on derivative contracts

(1,183)

270

(1,183)

513

Interest and other income

63

13

283

26

Interest expense

(518)

(32)

(584)

(404)

Income (loss) before income taxes

446

17,898

4,019

44,989

Income tax (expense) benefit

(157)

(3,941)

(1,174)

(9,938)

Net income (loss)

$

289

$

13,957

$

2,845

$

35,051

Net income (loss) per common share:

 

 

 

 

Basic

$

0.01

$

0.42

$

0.09

$

1.04

Diluted

$

0.01

$

0.41

$

0.08

$

1.04

Weighted average number of common shares outstanding:

 

 

 

 

Basic

32,702

33,013

32,692

33,108

Diluted

32,854

33,156

32,920

33,291

See accompanying notes to unaudited condensed consolidated condensed financial statements.


5

Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statement of Changes in Stockholders' Equity
For the Six Months Ended December 31, 2017
(Unaudited)

Table of Contents

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


EVOLUTION PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)

Nine Months Ended March 31, 

 

    

2024

    

2023

Cash flows from operating activities:

 

 

Net income (loss)

$

2,845

$

35,051

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

Depletion, depreciation, and accretion

14,760

10,439

Stock-based compensation

1,585

1,155

Settlement of asset retirement obligations

(19)

(119)

Deferred income taxes

124

(100)

Unrealized (gain) loss on derivative contracts

1,063

(1,994)

Accrued settlements on derivative contracts

94

(1,130)

Other

(3)

Changes in operating assets and liabilities:

 

Receivables from crude oil, natural gas, and natural gas liquids revenues

(4,734)

16,483

Prepaid expenses and other current assets

(1,425)

(980)

Accounts payable and accrued liabilities

814

(8,146)

State and federal income taxes payable

(365)

1,063

Net cash provided by operating activities

14,742

51,719

Cash flows from investing activities:

Acquisition of oil and natural gas properties

(43,788)

(31)

Capital expenditures for oil and natural gas properties

(8,353)

(4,234)

Net cash used in investing activities

(52,141)

(4,265)

Cash flows from financing activities:

 

 

Common stock dividends paid

(12,037)

(12,114)

Common stock repurchases, including stock surrendered for tax withholding

(1,031)

(3,983)

Borrowings under senior secured credit facility

42,500

Repayments of senior secured credit facility

(21,250)

Net cash (used in) provided by financing activities

29,432

(37,347)

Net increase (decrease) in cash and cash equivalents

(7,967)

10,107

Cash and cash equivalents, beginning of period

11,034

8,280

Cash and cash equivalents, end of period

$

3,067

$

18,387

Supplemental disclosures of cash flow information:

Non-cash investing and financing transactions:

Increase (decrease) in accrued capital expenditures for oil and natural gas properties

$

2,193

$

(141)

Oil and natural gas property costs attributable to the recognition of asset retirement obligations

90

See accompanying notes to unaudited condensed consolidated condensed financial statements.


6


5

Table of Contents

EVOLUTION PETROLEUM CORPORATION

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

(In thousands)

 

Additional

 

 

Total

 

Common Stock

Paid-in

Retained

Treasury

Stockholders'

    

Shares

    

Par Value

    

Capital

    

Earnings

    

Stock

    

Equity

For the Three Months Ended March 31, 2024

Balances at December 31, 2023

33,507

$

34

$

40,920

$

46,485

$

$

87,439

Issuance of restricted common stock

5

Common stock repurchases, including stock surrendered for tax withholding

(818)

(818)

Retirements of treasury stock

(152)

(1)

(817)

818

Stock-based compensation

549

549

Net income (loss)

289

289

Common stock dividends paid

(4,003)

(4,003)

Balances at March 31, 2024

33,360

$

33

$

40,652

$

42,771

$

$

83,456

For the Nine Months Ended March 31, 2024

Balances at June 30, 2023

33,248

$

33

$

40,098

$

51,963

$

$

92,094

Issuance of restricted common stock

293

1

(1)

Common stock repurchases, including stock surrendered for tax withholding

(1,031)

(1,031)

Retirements of treasury stock

(181)

(1)

(1,030)

1,031

Stock-based compensation

1,585

1,585

Net income (loss)

2,845

2,845

Common stock dividends paid

(12,037)

(12,037)

Balances at March 31, 2024

33,360

$

33

$

40,652

$

42,771

$

$

83,456

For the Three Months Ended March 31, 2023

Balances at December 31, 2022

33,808

$

34

$

43,243

$

45,861

$

$

89,138

Issuance of restricted common stock

101

Common stock repurchases, including stock surrendered for tax withholding

(3,896)

(3,896)

Retirements of treasury stock

(638)

(1)

(3,895)

3,896

Stock-based compensation

453

453

Net income (loss)

13,957

13,957

Common stock dividends paid

(4,029)

(4,029)

Balances at March 31, 2023

33,271

$

33

$

39,801

$

55,789

$

$

95,623

For the Nine Months Ended March 31, 2023

Balances at June 30, 2022

33,471

$

33

$

42,629

$

32,852

$

$

75,514

Issuance of restricted common stock

476

1

(1)

Forfeitures of restricted stock

(26)

Common stock repurchases, including stock surrendered for tax withholding

(3,983)

(3,983)

Retirements of treasury stock

(650)

(1)

(3,982)

3,983

Stock-based compensation

1,155

1,155

Net income (loss)

35,051

35,051

Common stock dividends paid

(12,114)

(12,114)

Balances at March 31, 2023

33,271

$

33

$

39,801

$

55,789

$

$

95,623

See accompanying notes to unaudited condensed consolidated financial statements.

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Financial Statement Presentation

Nature of Operations. Evolution Petroleum Corporation And Subsidiaries

Notes to Unaudited Consolidated Condensed Financial Statements



Note 1Organization(“Evolution,” and Basis of Preparation
Nature of Operations.  Evolution Petroleum Corporation ("EPM"), together with its consolidated subsidiaries, (the "Company", "we", "our" or "us"the “Company”), is an independent petroleumenergy company headquarteredfocused on maximizing returns to shareholders through the ownership of and investment in Houston, Texasonshore oil and incorporated undernatural gas properties in the lawsUnited States. The Company’s long-term goal is to maximize total shareholder return from a diversified portfolio of long-life oil and natural gas properties built through acquisitions and through selective development opportunities, production enhancement, and other exploitation efforts on its oil and natural gas properties.

The Company’s oil and natural gas properties consist of non-operated interests in the following areas: the SCOOP and STACK plays of the StateAnadarko Basin located in central Oklahoma; the Chaveroo oilfield in Chaves and Roosevelt Counties of Nevada. We are engaged primarilyNew Mexico; the Jonah Field in Sublette County, Wyoming; the Williston Basin in North Dakota; the Barnett Shale located in North Texas; the Hamilton Dome Field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir; the Delhi Holt-Bryant Unit in the development and production ofDelhi Field in Northeast Louisiana, a CO2 enhanced oil and gas reserves.

recovery project; as well as small overriding royalty interests in four onshore Texas wells.

Interim Financial Statements.  The accompanying unaudited condensed consolidated condensed financial statements have been prepared in accordance with generally accepted accounting principles generally accepted 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 accounting principles generally accepted in the United StatesGAAP 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 20172023 Annual Report on Form 10-K for the fiscal year ended June 30, 2017,2023, as filed with the SEC.SEC on September 13, 2023. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year.

The Company has evaluated events and transactions through the date of issuance of these unaudited condensed consolidated financial statements.

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

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

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

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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


Newstatements.

Recently Issued Accounting Pronouncements.


Pronouncements

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


operations, cash flow or disclosures.

In JanuaryJune 2016, the FASB issued ASU 2016-01,2016-13, Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities ("Credit Losses (“ASU 2016-01"2016-13”). The pronouncement requires equity investments (except those accountedASU 2016-13 changes the impairment model for under the equity method of accounting, or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income, requires public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes, requires separate presentation ofmost financial assets and financial liabilitiescertain other instruments, including trade and other receivables, and requires the use of a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. Early adoption is permitted and entities must adopt the amendment using a modified retrospective approach to the first reporting period in which the guidance is effective. For smaller reporting companies, as provided by measurement categoryASU 2019-10, Financial Instruments - Credit Losses (Topic 326), Derivatives and form of financial asset,Hedging (Topic 815), and eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value thatLeases (Topic 842), ASU 2016-13 is required to be disclosed for financial instruments measured at amortized cost. These changes become effective for fiscal yearsannual periods, including interim periods within those annual periods, beginning after December 15, 2017.2022. The expectedCompany adopted ASU 2016-13 effective July 1, 2023. The adoption methoddid not have a material effect on the Company’s financial position, results of ASU 2016-01 is being evaluatedoperations, cash flows or disclosures.

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

Note 2. Revenue Recognition

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


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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Evolution Petroleum Corporation And Subsidiaries
Notes

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

 

Three Months Ended

Nine Months Ended

March 31, 

March 31, 

 

    

2024

2023

2024

    

2023

Revenues

Crude oil

$

14,538

$

11,799

$

38,913

$

40,062

Natural gas

5,860

21,598

17,943

58,816

Natural gas liquids

2,627

3,470

7,794

11,462

Total revenues

$

23,025

$

36,867

$

64,650

$

110,340

In the Jonah Field, the Company has elected to Unaudited Consolidated Condensed Financial Statements




In February 2016,take its natural gas and NGL working interest production in-kind and markets its NGL production to Enterprise Products Partners L.P. and its natural gas production to different purchasers.

The Company does not take production in-kind at any of its other properties and does not negotiate contracts with customers for such production. The Company recognizes crude oil, natural gas, and NGL production revenue at the FASB issued ASU 2016-02 , Leases (“ASU 2016-02”point in time when custody and title (“control”), which relates of the product transfers to the accounting for leasing transactions. This standard requires a lesseecustomer. The sales of oil and natural gas are made under contracts which the Company’s third-party operators of its wells have negotiated with customers, which typically include variable consideration that is based on pricing tied to record on the balance sheet the assetslocal indices and liabilities for the rights and obligations created by leases with lease terms of more than twelve months. In addition, this standard requires both lessees and lessors to disclose certain key information about lease transactions. This standard will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years.  We are evaluating the impact the adoption of ASU 2016-02 will have on our consolidated financial statements.


In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classifiedvolumes delivered in the statementcurrent month. The Company typically receives payment from the sale of cash flows.oil and natural gas production one to two months after delivery.

Judgments made in applying the guidance in ASC 606, Revenue from Contracts with Customers, relate primarily to determining the point in time when control of product transfers to the customer. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear orCompany does not include specific guidance. This standard will be effective for fiscal years beginning after December 15, 2017,believe that significant judgments are required with respect to the determination of the transaction price, including interim periods within those fiscal yearsamounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with early adoption permitted, provided that it is adopted in its entirety in the same period. Currently,predictable differentials. Accordingly, the Company does not expectconsider estimates of variable consideration to be constrained.

The Company’s contractual performance obligations arise upon the impactproduction of adopting ASU 2016-15hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied upon control of produced hydrocarbons transferring to a customer at a specified delivery point. Consideration is allocated to completed performance obligations at the end of an accounting period.

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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 3. Acquisitions

SCOOP/STACK Acquisitions

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

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

Chaveroo Oilfield Participation Agreement

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

Upon signing the Participation Agreement, the Company paid total cash flows.


Note 2 — Receivables

consideration of $0.4 million, which includes less than $0.1 million of capitalized transactions costs, in exchange for a 50% working interest share in the existing leases associated with two initial development blocks. As of DecemberMarch 31, 20172024, the Company has participated in the drilling and completion of the first development block, consisting of three gross wells (1.5 net wells). Following the completion of the second development block, the Company will have the right, but not the obligation, to elect to participate and acquire a 50% working interest share in additional development blocks at a fixed price of $450 per net acre for up to a total of approximately 16,000 gross acres.

Note 4. Property and Equipment

Property and equipment as of March 31, 2024 and June 30, 2017, our receivables2023 consisted of the following:following (in thousands):

    

March 31, 2024

    

June 30, 2023

Oil and natural gas properties

 

 

Property costs subject to amortization

$

247,106

$

197,049

Less: Accumulated depletion, depreciation, and impairment

(104,949)

(91,268)

Oil and natural gas properties, net

$

142,157

$

105,781

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


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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Note 3 — Prepaid Expenses

depletion, exceed the discounted future net revenues of proved oil and Other Current Assets


Asnatural gas reserves, net of December 31, 2017deferred taxes, such excess capitalized costs would be charged to expense as a write-down of oil and June 30, 2017, our prepaid expenses and other current assets consistednatural gas properties.

Additionally, the Company assesses all properties classified as unevaluated property on a quarterly basis for possible impairment. The Company assesses properties on an individual basis or as a group, if properties are individually insignificant. The assessment includes consideration of the following:


 December 31,
2017
 June 30,
2017
Prepaid insurance$86,904
 $169,416
Retainers and deposits7,589
 7,553
Prepaid federal and state income taxes674,028
 121,232
Other prepaid expenses55,527
 89,471
Prepaid expenses and other current assets$824,048
 $387,672


7

Tablefollowing factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of Contents
Evolution Petroleum Corporation And Subsidiaries
Notesproved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to Unaudited Consolidated Condensed Financial Statements


Note 4 —Propertydate for such property and Equipment
Asall or a portion of Decemberthe associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the full cost ceiling test limitation.

Depletion of oil and natural gas properties was $13.7 million and $9.6 million for the nine months ended March 31, 20172024 and June 30, 2017, our2023, respectively. During the nine months ended March 31, 2024 and 2023, the Company incurred development capital expenditures of $9.4 million and $4.4 million, respectively.

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

At March 31, 2023, the ceiling test value of the following:

 December 31,
2017
 June 30,
2017
Oil and natural gas properties 
  
Property costs subject to amortization$86,403,877
 $84,962,933
Less: Accumulated depreciation, depletion, and amortization(26,310,070) (23,172,865)
Unproved properties not subject to amortization
 
Oil and natural gas properties, net$60,093,807
 $61,790,068
Other property and equipment 
  
Furniture, fixtures, office equipment and other, at cost$135,377
 $135,377
Less: Accumulated depreciation(103,112) (94,688)
Other property and equipment, net$32,265
 $40,689
DuringCompany’s reserves was calculated based on the six monthsfirst-day-of the month average for the 12-months ended DecemberMarch 31, 20172023 of the WTI crude oil spot price of $91.38 per barrel and Henry Hub natural gas spot price of $5.97 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $47.07, which was based on historical prices received as NGLs do not have any single comparable reference index price. Using these prices, at March 31, 2023 the cost center ceiling was higher than the capitalized costs of oil and natural gas properties and, as a result, no write-down was applicable.

Note 5. Senior Secured Credit Facility

On April 11, 2016, the Company incurred capital expendituresentered into a three-year, senior secured reserve-based credit facility, as amended, (the “Senior Secured Credit Facility”) with MidFirst Bank in an amount up to $50.0 million with a current borrowing base of $1.4$50.0 million. On May 5, 2023, the Company entered into the Tenth Amendment to the Senior Secured Credit Facility extending the maturity to April 9, 2026. The Tenth Amendment also replaced the London Interbank Offered Rate ("LIBOR") with the Secured Overnight Financing Rate (“SOFR”) plus a credit spread adjustment of 0.05% to effectively convert SOFR to a LIBOR equivalent and modifies the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, to $95.0 million. The borrowing base will be redetermined semiannually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company’s oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. The Senior Secured Credit Facility carries a commitment fee of 0.25% per annum on the undrawn portion of the borrowing base. Any borrowings under the Senior Secured Credit Facility will bear interest, at the Company’s option, at either SOFR plus 2.80%, which includes a 0.05% credit spread adjustment from LIBOR, subject to a minimum SOFR of 0.50%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%.

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

On November 9, 2021, the Company entered into the Eighth Amendment to the Senior Secured Credit Facility. This amendment, among other things, increased the borrowing base to $50.0 million and $6.5 million, respectively,added a hedging covenant whereby the Company must hedge a minimum of 25% to 75% of future production on a rolling 12-month basis when 25% or more of the borrowing base is utilized. The hedging covenant was amended in the Delhi field.subsequent amendments, as discussed above.

Note 6. Income Taxes

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

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

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

Note 7. Derivatives

The Company is exposed to certain risks relating to its ongoing business operations, including commodity price risk and interest rate risk. In accordance with the Company’s strategy and the requirements under the Senior Secured Credit Facility (as discussed in Note 5,Other Assets


“Senior Secured Credit Facility”), it may hedge or may be required to hedge a varying portion of anticipated oil and natural gas production for future periods. Derivatives are carried at fair value on the unaudited condensed consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the unaudited condensed consolidated statements of operations for the period in which the change occurs. The Company’s hedge strategies and objectives may change significantly as its operational profile changes or as required under the Senior Secured Credit Facility. The Company does not enter into derivative contracts for speculative trading purposes.

It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of DecemberMarch 31, 20172024, the Company did not post collateral under any of its derivative contracts during the periods in which contracts were open as they were secured under the Company’s Senior Secured Credit Facility.

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

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

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets as of March 31, 2024 and June 30, 2017, other assets consisted2023 (in thousands):

Derivatives not designated

as hedging contracts

Balance sheet

Derivative Contract Assets

Balance sheet

Derivative Contract Liabilities

under ASC 815

    

location

    

March 31, 2024

    

June 30, 2023

    

location

    

March 31, 2024

    

June 30, 2023

Commodity contracts

Current assets - derivative contract assets

$

347

$

Current liabilities - derivative contract liabilities

$

1,410

$

Commodity contracts

Other assets - derivative contract assets

Long term liabilities - derivative contract liabilities

Total derivatives not designated as hedging contracts under ASC 815

$

347

$

$

1,410

$

The following table summarizes the location and amounts of the following:

 December 31,
2017
 June 30,
2017
Royalty rights$108,512
 $108,512
Less: Accumulated amortization of royalty rights(27,128) (20,346)
Investment in Well Lift Inc., at cost108,750
 108,750
Deferred loan costs168,972
 168,972
Less: Accumulated amortization of deferred loan costs(98,638) (70,504)
Other assets, net$260,468
 $295,384
Our royalty rightsCompany’s realized and investmentunrealized gains and losses on derivative contracts in Well Lift, Inc. ("WLI") resulted from the separationCompany’s unaudited condensed consolidated statements of our artificial lift technology operations for the three and nine months ended March 31, 2024 and 2023 (in thousands). “Realized gain (loss) on derivative contracts” represents all receipts (payments) on derivative contracts settled during the period. “Unrealized gain (loss) on derivative contracts” represents the net change in December 2015. We conveyed our patents and other intellectual property to WLI and retained a 5% royalty on future gross revenues associated the technology. We own 17.5%mark-to-market valuation of the common stockderivative contracts.

Derivatives not designated

Location of gain (loss)

Three Months Ended

Nine Months Ended

as hedging contracts

recognized in income on

March 31, 

March 31, 

under ASC 815

    

derivative contracts

    

2024

2023

2024

    

2023

Commodity contracts:

Realized gain (loss) on derivative contracts

Other income and expenses - net gain (loss) on derivative contracts

$

(120)

$

465

$

(120)

$

(1,481)

Unrealized gain (loss) on derivative contracts

Other income and expenses - net gain (loss) on derivative contracts

(1,063)

(195)

(1,063)

1,994

Total net gain (loss) on derivative contracts

$

(1,183)

$

270

$

(1,183)

$

513

As of WLIMarch 31, 2024, the Company had the following open crude oil and account for our investment undernatural gas derivative contracts:

Weighted Average

Weighted Average

Weighted Average

Volumes in

Swap Price per

Floor Price per

Ceiling Price per

Period

    

Instrument

    

Commodity

    

MMBTU/BBL

MMBTU/BBL

    

MMBTU/BBL

    

MMBTU/BBL

April 2024 - June 2024

Fixed-Price Swap

Crude Oil

24,250

$

73.41

April 2024 - June 2024

Fixed-Price Swap

Crude Oil

14,467

73.30

April 2024 - June 2024

Put

Crude Oil

38,717

$

75.00

July 2024 - December 2024

Fixed-Price Swap

Crude Oil

73,558

74.20

July 2024 - December 2024

Collar

Crude Oil

73,558

70.00

$

77.40

January 2025 - March 2025

Collar

Crude Oil

42,566

68.00

73.77

January 2025 - February 2025

Fixed-Price Swap

Natural Gas

312,286

3.56

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Subsequent to March 31, 2024, the cost method. Any dividends paid are recorded as incomeCompany entered into the following open crude oil and any returnnatural gas derivative contracts:

Weighted Average

Weighted Average

Weighted Average

Volumes in

Swap Price per

Floor Price per

Ceiling Price per

Period

    

Instrument

    

Commodity

    

MMBTU/BBL

MMBTU/BBL

    

MMBTU/BBL

    

MMBTU/BBL

April 2025 - June 2025

Collar

Crude Oil

41,601

$

65.00

$

84.00

March 2025 - December 2026

Fixed-Price Swap

Natural Gas

3,170,705

$

3.60

The Company presents the fair value of capital reduces our cost basisits derivative contracts at the gross amounts in the investment. Our investment in WLI is evaluated for impairment at least quarterly or when management identifies any events or changes in circumstances that might have a significant adverse effectunaudited condensed consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the investment. ThereCompany’s derivative contracts as of March 31, 2024 and June 30, 2023 (in thousands):

Derivative Contracts Assets

Derivative Contracts Liabilities

Offsetting of Derivative Assets and Liabilities

    

March 31, 2024

    

June 30, 2023

    

March 31, 2024

    

June 30, 2023

Gross amounts presented in the Consolidated Balance Sheet

$

347

$

$

1,410

$

Amounts not offset in the Consolidated Balance Sheet

(347)

(347)

Net amount

$

$

$

1,063

$

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

Note 8. Fair Value Measurement

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

The three levels are defined as follows:

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

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

Level 3—Unobservable inputs for which there are little or no published 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 for this private investment, so itincorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s unaudited condensed consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. Fair value is not practicabledefined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable (Level 1) market

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

March 31, 2024

    

Level 1

    

Level 2

    

Level 3

    

Total

Assets

Derivative contract assets

$

$

347

$

$

347

Liabilities

Derivative contract liabilities

$

$

1,410

$

$

1,410

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

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

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

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

The Company follows the provisions of ASC 820, for nonfinancial assets and liabilities measured at fair value on a periodicnon-recurring basis.



8

Evolution Petroleum Corporation And Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


Note 6Accrued Liabilities and Other
As of December 31, 2017 and June 30, 2017, our other current liabilities consisted of the following:
 December 31,
2017
 June 30,
2017
Accrued incentive and other compensation$292,382
 $413,113
Accrued severance payments46,719
 
Asset retirement obligations due within one year35,539
 35,115
Accrued royalties, including suspended accounts11,524
 17,708
Accrued franchise taxes82,800
 150,062
Accrued ad valorem taxes191,503
 108,641
Accrued liabilities and other$660,467
 $724,639
Note 7Asset Retirement Obligations
Our asset retirement obligations represent(“ARO”) for which fair value is calculated using discounted future cash flows derived from historical costs and management’s expectations of future cost environments. Significant Level 3 inputs used in the calculation of ARO include the costs of plugging and abandoning wells, surface restoration, and reserve lives. Subsequent to initial recognition, revisions to estimated asset retirement obligations are made when changes occur for input values. See Note 9, “Asset Retirement Obligations, for a reconciliation of the beginning and ending balances of the liability for the Company’s ARO.

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 9. Asset Retirement Obligations

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

The following is a reconciliation of the beginning and ending asset retirement obligationsactivity related to the Company’s ARO liability (inclusive of the current portion) for the six monthsperiod ended DecemberMarch 31, 2017 and for the year ended June 30, 2017:

2024 (in thousands):

 

    

March 31, 2024

Asset retirement obligations — beginning of period

$

17,067

Liabilities acquired(1)

90

Accretion of discount

1,080

Asset retirement obligations — end of period

18,237

Less: current asset retirement obligations

(158)

Long-term portion of asset retirement obligations

$

18,079

 December 31,
2017
 June 30,
2017
Asset retirement obligations — beginning of period$1,288,743
 $962,196
Liabilities incurred
 52,792
Liabilities settled
 (157,164)
Liabilities sold
 (47,817)
Accretion of discount44,602
 59,664
Revision of previous estimates(778) 419,072
Asset retirement obligations — end of period$1,332,567
 $1,288,743
Less current portion in accrued liabilities(35,539) (35,115)
Long-term portion of asset retirement obligations$1,297,028
 $1,253,628
(1)See Note 3, “Acquisitions,” for additional information on the Company’s acquisition activities.

Note 8 —10. Commitments and Contingencies

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

Note 11. Stockholders’ Equity


Common Stock

As of DecemberMarch 31, 2017, we2024, the Company had 33,171,514 shares33,359,854 shares of common stock outstanding.


The Company began paying quarterly cash dividends on common stock in December 2013. WeAs of March 31, 2024, the Company has cumulatively paid over $114.4 million in cash dividends. The Company paid dividends of $4,969,335$12.0 million and $3,801,962$12.1 million to ourits common shareholdersstockholders during the sixnine months ended DecemberMarch 31, 20172024 and 2016,2023, respectively. These dividend payments consisted

18

Table of two quarterlyContents

EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table reflects the dividends of $0.075paid per share each duringwithin the six months ended December 31, 2017 and quarterly dividend payments of $0.05 and $0.065 per share during the six months ended December 31, 2016.


In May 2015,respective three-month periods:

Fiscal Year

    

2024

    

2023

Third quarter ended March 31,

$

0.120

$

0.120

Second quarter ended December 31,

0.120

0.120

First quarter ended September 30,

0.120

0.120

On September 8, 2022, the Board of Directors approved a share repurchase program, coveringunder which the Company is authorized to repurchase up to $5$25.0 million of the Company'sits common stock. Between June 2015 and December 2015, the Company spent $1,609,008 to repurchase 265,762 common shares at an average price of $6.05 per share. There have been no shares repurchasedstock in the open market sincethrough December 2015. Under31, 2024. The Company intends to fund repurchases from working capital and cash provided by operating activities. The Board of Directors along with the program's terms,management team believe that a share repurchase program is complimentary to the existing dividend policy and is a tax efficient means to further improve shareholder return. The shares aremay be repurchased only on thefrom time to time in open market andtransactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the requirementsnumber and value of shares repurchased under the program, will depend on a variety of factors, including management’s assessment of the Securitiesintrinsic value of the Company’s shares, the market price of the Company’s common stock, the Company’s capital needs and Exchange Commission. Such shares are initially recorded as treasury stock, then subsequently canceled. The timing and amount of repurchases depends upon several factors, including financial resources, andgeneral market and business conditions. There is no fixed termination dateeconomic conditions, and applicable legal requirements. The value of shares authorized for this repurchase program,by the Company’s Board of Directors does not require the Company to repurchase such shares or guarantee that such shares will be repurchased, and itthe program may be suspended, modified, or discontinued at any time.



9

Evolution Petroleum Corporation And Subsidiaries
NotesMarch 31, 2024, a total of 0.8 million shares of the Company’s common stock have been repurchased under the plan at a total cost of approximately $4.6 million, including incremental direct transaction costs.

In December 2022, the Company entered into a Rule 10b5-1 plan that authorized a broker to Unaudited Consolidated Condensed Financial Statements



repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan included a 30-day cooling off period that did not allow repurchases to commence until January 2023. The plan was effective until June 30, 2023 and had a maximum authorized amount of $5.0 million over that period. During the sixthree and nine months ended DecemberMarch 31, 20172023, 0.6 million shares of the Company’s common stock were repurchased under the plan at a total cost of approximately $3.9 million, including incremental direct transaction costs. These treasury shares were subsequently cancelled.

In November 2023, the Company entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and 2016,price. The plan is effective until June 30, 2024, unless extended, renewed or terminated by the Company, and has a maximum authorized amount of $0.8 million over that period. The Company may alter the terms of the plan from time to time to the extent it determines changes are necessary to achieve the intended objectives of the repurchase program. During the three and nine months ended March 31, 2024, 0.1 million shares of the Company’s common stock were repurchased under the plan at a total cost of approximately $0.8 million, including incremental direct transaction costs. These treasury shares were subsequently cancelled.

During the nine months ended March 31, 2024 and 2023, the Company acquired treasury stock from holdersupon the ordinary course of newly vestedscheduled vestings of employee stock-based awards to fund the recipients' payroll tax withholding obligations. TheThese treasury shares were subsequently canceled.cancelled. Such shares were valued at fair market value on the date of vesting, as reflected investing.

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Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes all treasury stock purchases during the following table:

nine months ended March 31, 2024 and 2023 (in thousands, except per share amounts):

Nine Months Ended

March 31, 

    

2024

2023

Number of treasury shares acquired(1)

181

650

Average cost per share(1)

$

5.70

$

6.13

Total cost of treasury shares acquired

$

1,031

$

3,983

 Six Months Ended 
 December 31,
 2017 2016
Number of treasury shares acquired55,018
 73,455
Average cost per share$7.19
 $6.26
Total cost of treasury shares acquired$395,550
 $459,858

Series A Cumulative Preferred Stock Called for Redemption

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

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

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

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

Expected Tax Treatment of Dividends


For the fiscal year ended June 30, 2017,2023, all preferred and common stock dividends for that fiscal year were treated for tax purposes as qualified dividend income to the recipients. Based on ourits current projections for the fiscal year endingended June 30, 2018, we expect2024, the Company expects all common stock dividends for such period to be treated as qualified dividend income.income to the recipients. Such projections are based on ourthe Company’s reasonable expectations as of DecemberMarch 31, 20172024 and are subject to change based on ourthe Company’s final tax calculations at the end of the fiscal year.

Note 9 —

Stock-Based Incentive Plan

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

The Evolution Petroleum Corporation 2016 Equity Incentive Plan (the(as amended, the “2016 Plan”), which replaced the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the "2004 Plan"). The 2016 Plan authorizes the issuance of 1,100,0003.6 million shares of common stock prior to its expiration on December 8, 2026. Incentives under the 2016 Plan may be granted to employees, directors, and consultants of the Company in any one or a combination of the following forms: incentive stock options and non-statutory stock options, stock appreciation rights, restricted stock awards and restricted stock unit awards, performance share awards, performance cash awards, and other forms of incentives valued in whole or in part by reference to, or otherwise based on, ourthe Company’s common stock, including its appreciation in value. As of DecemberMarch 31, 2017, 987,8452024 and June 30, 2023, approximately 0.9 million shares and 1.3 million shares, respectively, remained available for grant under the 2016 Plan.


At December 8, 2016, there were no shares available

The Company estimates the fair value of stock-based compensation awards on the grant date to provide the basis for future grants undercompensation expense. During the 2004 Plan. All outstanding awards granted underthree and nine months ended March 31, 2024, the 2004 Plan continueCompany recognized $0.5 million and $1.6 million, respectively, related to be subjectstock-based compensation. During the three and nine months ended March 31, 2023, the Company recognized $0.5 million and $1.2 million, respectively, related to stock-based compensation expense. Stock-based compensation expense is recorded as a component of “General and administrative expenses” on the terms and conditions as set forth in the agreements evidencing such awards and the termsunaudited condensed consolidated statements of the 2004 Plan. Under these agreements, we have outstanding grants ofoperations.

Time-Vested Restricted Stock Awards

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


Restricted Stock and Contingent Restricted Stock

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

10

Evolution Petroleum Corporation And Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


thresholds and are issued only upon vesting. Shares underlying Contingent Restricted Stock awards are reserved from the Plan they were granted under.

Service-basedCompany. These service-based awards vest with continuous employment by the Company, generally in annual installments over a four-yearterms of three to four years. Awards to the Company’s directors generally have one-year cliff vesting. For such awards, grant date fair value is based on market value of the Company’s common stock at the time of grant. This value is then amortized ratably over the service period. Certain awards contain otherPreviously recognized amortization expense subsequent to the last vesting periods, including quarterly installments and one-year vesting.date of an award is reversed in the event that the holder has no longer rendered service to the Company resulting in forfeiture of the award.

20

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Performance-Based Restricted Stock grants which vestAwards and Performance-Based Contingent Stock Units

Performance-based restricted stock awards and performance-based contingent stock units contain market-based vesting conditions based on servicethe price of the Company’s common stock, the intrinsic value indexed solely to its common stock or the intrinsic value indexed to its common stock compared to the performance of the common stock of its peers. The common shares underlying the Company’s performance-based restricted stock awards are valued at the fair market valueissued on the date of grant and amortized overparticipate in dividends paid by the service period. DuringCompany and expire after a maximum of four years from the six months ended December 31, 2017, we granted 112,155 service-based Restricted Stock awards, including 45,211 awards to employeesdate of grant if unvested. Performance-based contingent share units do not participate in dividends and 66,944 awards to directors, substantially all of which have a one-year vesting period. We did not grant any performance-basedshares are only issued in part or market based awards, nor any Contingent Restricted Stock awards, during this period.


Performance-based grants vestin full upon the attainment of earnings, revenuevesting conditions, generally have a lower probability of achievement and other operational goalsexpire after a maximum of four years from the date of grant if unvested. Shares underlying performance-based contingent share units are reserved from the 2016 Plan. Performance-based restricted stock awards and require thatcontingent restricted stock units are valued using a Monte Carlo simulation and geometric Brownian motion techniques applied to the recipient remain an employee or directorhistorical volatility of the Company’s total stock return compared to the historical volatilities of other companies or indices to which the Company throughcompares its performance and/or the Company’s absolute total stock return. For certain awards, this Monte Carlo simulation also provides an expected vesting date. The Company recognizesterm. Stock-based compensation expense for performance-based awardsis recognized ratably over the expected vesting period, basedso long as the award holder remains an employee of the Company. Previously recognized compensation expense is only reversed for the awards with market-based vesting conditions if the requisite service period is not rendered by the holder resulting in forfeiture of the award or as a result of regulatory required clawback.

Vesting of grants with performance-based vesting conditions is dependent on the grant date fair value when it is deemed probable, for accounting purposes, thatfuture price of the performance criteria will be achieved. The expected vesting period may be deemed to be shorter than the four-year term. As of December 31, 2017, certain contingent performance-based awards were not considered probable of vesting for accounting purposes and no compensation expense has been recognized with regard to these awards. If these awards are later determined to be probable of vesting, cumulative compensation expense would be recorded at that time and amortization would continue over the remaining expected vesting period.


Market-basedCompany’s common stock. Such awards vest in part or in full if the three-year trailing total returnreturns on the Company’s common stock exceedsfor a specified three-year period exceed the corresponding total returns of various quartiles of indices consisting of either peer companies or, in some cases, vest when the average of the Company’s closing common stock price over a broad market indexdefined measurement period meets or exceeds a required common stock price.

During the nine months ended March 31, 2024, the Company granted a total of companies0.4 million equity awards that included 0.2 million time-vested restricted stock awards, 0.1 million performance-based restricted stock awards, and 0.1 million performance-based contingent stock units.

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

For performance-based awards granted during the nine months ended March 31, 2024 and 2023, the assumptions used in our industry. The fair values and expected vesting periods of these awards are determined using athe Monte Carlo simulation based on the historical volatilityvaluations were as follows:

Nine Months Ended

March 31, 

    

2024

    

2023

Weighted average fair value of performance-based awards granted

$

3.58

$

6.52

Risk-free interest rate

4.87%

3.91% to 4.51%

Expected term in years

2.77

2.36 to 2.78

Expected volatility

55.0%

56.5% to 70.9%

Dividend yield

7.4%

6.1% to 7.8%

21

Table of the Company's total return compared to the historical volatilitiesContents

EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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


Unvested Restricted Stock awards at DecemberMarch 31, 20172024 consisted of the following:

Number of
Restricted
Shares
 Weighted
Average
Grant-Date
Fair Value
Service-based awards220,068
 $6.68
Performance-based awards50,360
 5.67
Market-based awards50,359
 5.44
Unvested Restricted Stock at December 31, 2017320,787
 $6.33

Weighted

Number of

Average

Restricted

Grant-Date

Award Type

    

Shares

    

Fair Value

Time-vested awards

407,103

$

6.59

Performance-based awards

278,688

5.46

Unvested at March 31, 2024

685,791

$

6.13

The following table sets forth the Restricted Stockrestricted stock award transactions for the sixnine months ended DecemberMarch 31, 2017:

 Number of
Restricted
Shares
 Weighted
Average
Grant-Date
Fair Value
 Unamortized Compensation Expense at December 31, 2017 Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2017391,624
 $6.22
    
Service-based shares granted112,155
 6.96
    
Vested(163,431) 6.52
    
Forfeited(19,561) 6.16
    
Unvested Restricted Stock at December 31, 2017320,787
 $6.33
 $1,510,203
 1.39

11

Evolution Petroleum Corporation And Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


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

Number of
Contingent
Restricted
Shares
 Weighted
Average
Grant-Date
Fair Value
Performance-based awards36,688
 $7.04
Market-based awards25,180
 3.42
Unvested contingent shares at December 31, 201761,868
 $5.57
2024:

Weighted

Weighted

Unamortized

Average

Number of

Average

Compensation

Remaining

Restricted

Grant-Date

Expense

Amortization

    

Shares

    

Fair Value

    

(In thousands)

    

Period (Years)

Unvested at June 30, 2023

595,414

6.48

$

2,827

2.4

Time-vested shares granted

157,192

6.22

Performance-based shares granted

136,315

4.80

Vested

(203,130)

6.33

Unvested at March 31, 2024

685,791

$

6.13

$

2,995

1.9

The following table sets forth Contingent Restricted Stockcontingent restricted stock unit transactions for the sixnine months ended DecemberMarch 31, 2017:2024:

Weighted

Unamortized

Average

Number of

Weighted Average

Compensation

Remaining

Restricted

Grant-Date

Expense

Amortization

 

    

Stock Units

    

Fair Value

    

(In thousands)

    

Period (Years)

Unvested at June 30, 2023

96,398

$

3.49

$

195

1.9

Performance-based awards granted

102,239

1.95

Unvested at March 31, 2024

198,637

$

2.70

$

275

1.8

22

 Number of
Contingent
Restricted
Shares
 Weighted
Average
Grant-Date
Fair Value
 Unamortized Compensation Expense at December 31, 2017 (1) Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2017113,270
 $4.64
    
Vested(46,630) 3.34
    
Forfeited(4,772) 5.30
    
Unvested contingent shares at December 31, 201761,868
 $5.57
 $84,005
 1.03
(1) Excludes $115,665 of potential future compensation expense for contingent performance-based awards for which vesting is not considered probable at this time for accounting purposes.
Stock-based compensation expense related to Restricted Stock and Contingent Restricted Stock grants for the three months ended December 31, 2017 and 2016 was $484,326 and $275,184, respectively. For the corresponding six month periods, non-cash stock compensation expense was $971,810 and $586,872, respectively.

Note 10Derivatives
From time to time, the Company may use derivative instruments to reduce its exposure to crude oil price volatility of its near-term forecasted production. The Company's objectives are to achieve a more predictable level of cash flows to support the Company’s capital expenditure programs and to provide better financial visibility for the payment of dividends on common stock. The Company may use both fixed price swap agreements and costless collars to manage its exposure to crude oil and other commodity price risk. While these derivative instruments are intended to limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The Company does not intend to enter into derivative instruments for speculative or trading purposes.
The Company accounts for derivatives under the provisions of ASC 815 Derivatives and Hedging ("ASC 815") under which the Company records the fair value of the instruments on the balance sheet at each reporting date, with changes in fair value recognized in other non-operating income and expense. Given the cost and complexity, the Company has elected not to use cash flow hedge accounting provided under ASC 815. Under cash flow hedge accounting, a portion of the change in fair value of the derivative instruments, if effective in hedging the underlying commodity risk, would be deferred in other comprehensive income and recognized in earnings only when the underlying hedged item impacts earnings.
These derivative instruments can result in both fair value asset and liability positions held with each counterparty. These positions are offset to a single net fair value asset or liability at the end of each reporting period. The Company nets its fair value amounts of derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. As of June 30, 2017 and December 31, 2017, the Company had no derivative asset or liability positions.
The Company monitors the credit rating of its counterparties and believes it does not have significant credit risk. Accordingly, we do not currently require our counterparties to post collateral to support the net asset positions of our derivative instruments. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties to its derivative instruments.

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Evolution Petroleum Corporation And Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


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

EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 11Income Taxes

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

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

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

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

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


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Evolution Petroleum Corporation And Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


Note 12 —Net Income Per12. Earnings (Loss) per Common Share

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

 Three Months Ended December 31, Six Months Ended December 31,
 2017 2016 2017 2016
Numerator 
  
  
  
Net income available to common shareholders$9,876,848
 $2,307,634
 $12,017,380
 $2,870,979
Denominator 
  
  
  
Weighted average number of common shares — Basic33,109,448
 33,047,166
 33,099,546
 33,002,088
Effect of dilutive securities: 
  
  
  
   Contingent restricted stock grants30,830
 9,836
 40,711
 10,909
   Stock options
 26,025
 
 24,272
Weighted average number of common shares and dilutive potential common shares used in diluted EPS33,140,278
 33,083,027
 33,140,257
 33,037,269
        
Net income per common share — Basic$0.30
 $0.07
 $0.36
 $0.09
Net income per common share — Diluted$0.30
 $0.07
 $0.36
 $0.09
Outstanding potentially dilutive securities ascommon share, reflecting the application of Decemberthe two-class method (in thousands, except per share amounts):

 

Three Months Ended

Nine Months Ended

March 31, 

March 31, 

 

    

2024

2023

2024

    

2023

Numerator

 

 

 

 

Net income (loss)

$

289

$

13,957

$

2,845

$

35,051

Undistributed earnings allocated to unvested restricted stock

(6)

(253)

(58)

(515)

Net income (loss) for earnings per share calculation

$

283

$

13,704

$

2,787

$

34,536

 

 

 

 

Denominator

Weighted average number of common shares outstanding — Basic

32,702

33,013

32,692

33,108

Effect of dilutive securities:

Unvested restricted stock awards

124

143

192

178

Unvested contingent restricted stock units

28

36

5

Weighted average number of common shares and dilutive potential common shares used in diluted earnings per share

32,854

33,156

32,920

33,291

Net income (loss) per common share — Basic

$

0.01

$

0.42

$

0.09

$

1.04

Net income (loss) per common share — Diluted

$

0.01

$

0.41

$

0.08

$

1.04

Unvested restricted stock awards (both time-vested and performance-based), totaling approximately 0.1 million for each of the three and nine months ended March 31, 20172024 were as follows:

Outstanding Potentially Dilutive SecuritiesWeighted
Average
Exercise Price
At December 31, 2017
Contingent Restricted Stock grants
61,868
Outstanding potentially dilutive securities asnot included in the computation of December 31, 2016 were as follows:
Outstanding Potentially Dilutive SecuritiesWeighted
Average
Exercise Price
 At December 31, 2016
Contingent Restricted Stock grants$
 113,270
Stock Options2.19
 35,231
Total outstanding potentially dilutive securities$0.52
 148,501
Note 13 — Senior Secured Credit Agreement

On April 11, 2016,diluted earnings per common share because the Company entered into a three-year, senior secured reserve-based credit facility ("Facility") in an amount up to $50 million. The Facility replaces the Company's previous unsecured credit facility which expired in April 2016. The borrowing base under the Facility haseffect would have been set at $10anti-dilutive.

Unvested restricted stock awards (both time-vested and performance-based), totaling approximately 0.3 million and was subsequently increased to $400.1 million effective February 1, 2018. As of Decemberfor the three and nine months ended March 31, 2017, the Company was in compliance with all covenants contained2023, respectively, were not included in the Facility,computation of diluted earnings per common share because the effect would have been anti-dilutive.

In addition, unvested performance-based restricted stock awards and no amounts were outstanding underunvested contingent restricted stock units that would not meet the Facility.

Borrowings from the Facility may be used for the acquisition and development of oil and gas properties and for letters of credit and other general corporate purposes. Availability of borrowings under the Facility is subject to semi-annual borrowing base redeterminations.
The Facility included a placement fee of 0.50% on the initial borrowing base, amounting to $50,000, and carries a commitment fee of 0.25% per annum on the undrawn portion of the borrowing base. Any borrowings under the Facility will bear interest, at the Company’s option, at either LIBOR plus 2.75% or the Prime Rate, as defined, plus 1.00%. The Facility contains financial covenants including a requirement that the Company maintain,performance criteria as of the last dayperiod end are excluded from the computation of each fiscal quarter, (a) a maximum total leverage ratio of not more than 3.00 to 1.00, (b) a debt service coverage ratio of not less than 1.10 to 1.00, and (c) a consolidated tangible net worth of not less than $40 million, all as defined under the Facility.diluted earnings per common share.


23

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Evolution Petroleum Corporation And Subsidiaries
Notes to Unaudited Consolidated Condensed

Note 13. Additional Financial Statements

Statement Information

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

 

    

March 31, 2024

    

June 30, 2023

Prepaid expenses and other current assets:

Other receivables(1)

$

2,576

$

18

Prepaid insurance

311

727

Prepaid federal and state income taxes

1,980

805

Carryback of EOR tax credit

347

347

Advances to operators

594

Prepaid other

467

380

Total prepaid expenses and other current assets

$

6,275

$

2,277

Other assets:

Deposit

$

1,158

$

1,158

Right of use asset under operating lease

160

183

Total other assets

$

1,318

$

1,341

Accrued liabilities and other:

Accrued payables

$

2,789

$

3,005

Accrued capital expenditures

167

Accrued incentive and other compensation

902

941

Accrued royalties payable

625

977

Accrued taxes other than federal and state income tax

1,166

739

Accrued severance

81

Accrued settlements on derivative contracts

94

Operating lease liability

97

59

Asset retirement obligations due within one year

158

55

Accrued - other

154

3

Total accrued liabilities and other

$

5,985

$

6,027



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

Note 14. Subsequent Events

Dividend Declaration

On May 6, 2024, the Company incurred $168,972declared a quarterly cash dividend of debt issuance costs. Such costs were capitalized in Other Assets$0.120 per share of common stock to shareholders of record on June 14, 2024 and are being amortized to expense. The unamortized balance in debt issuance costs related to the Facility was $70,334 aspayable on June 28, 2024.

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Table of December 31, 2017.Contents

Note 14 — Commitments and Contingencies
We are subject to various claims and contingencies in the normal course of business. In addition, from time to time, we receive communications from government or regulatory agencies concerning investigations or allegations of noncompliance with laws or regulations in jurisdictions in which we operate. At a minimum we disclose such matters if we believe it is reasonably possible that a future event or events will confirm a loss through impairment of an asset or the incurrence of a liability. We accrue a loss if we believe it is probable that a future event or events will confirm a loss and we can reasonably estimate such loss and we do not accrue future legal costs related to that loss. Furthermore, we will disclose any matter that is unasserted if we consider it probable that a claim will be asserted and there is a reasonable possibility that the outcome will be unfavorable. We expense legal defense costs as they are incurred.

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

Lease Commitments.  We have a non-cancelable operating lease for office space that expires on May 31, 2019. Future minimum lease commitments as of December 31, 2017 under this operating lease are as follows: 
Twelve months ended December 31, 
2018$73,073
2019 (through May)$30,447
Rent expense for the three months ended December 31, 2017 and 2016 was $19,198 and $18,569, respectively. Rent expense for the six months ended December 31, 2017 and 2016 was $39,049 and $53,425, respectively.

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

The following discussion

Executive Overview

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

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

This Form 10-Q and the information referenced herein contain forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 (the “Securities Act”) 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 our 2017 Annual Report on Form 10-K for the year ended June 30, 2017 as filed with the Securities and Exchange Commission. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Evolution Petroleum Corporation are expressly qualified in their entirety by this cautionary statement.
We use the terms, “EPM,” “Company,” “we,” “us” and “our” to refer to Evolution Petroleum Corporation and its wholly owned subsidiaries.

Executive Overview
General

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

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

Highlights for our Second Quarter of Fiscal 2018 and Operations Update

"

Critical Accounting Policies

Commonly Used Terms

Current quarter"quarter” refers to the three months ended DecemberMarch 31, 2017, the Company's second2024, our third quarter of fiscal 2018.


"Prior quarter"year 2024.

“Year-ago quarter” refers to the three months ended September 30, 2017, the Company's firstMarch 31, 2023, our third quarter of fiscal 2018.year 2023.

Executive Overview

General

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

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

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

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

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

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


25

"Year-ago quarter" refers

Table of Contents

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

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

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

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

Recent Developments

SCOOP/STACK Acquisitions


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

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

Senior Secured Credit Facility

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

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Appointment of Chief Accounting Officer

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

Share Repurchase Program

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

Chaveroo Oilfield Participation Agreement


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

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

During the three months ended December 31, 2016, the Company's second quarterSeptember 30, 2023, we paid total cash consideration of fiscal 2017.



Highlights$0.4 million, which includes less than $0.1 million of capitalized transaction costs, in exchange for the Quarter:
We reported revenues of $11.1 million for the current quarter, an increase of 30% over both the prior and year-ago quarters.
Current quarter net income was $9.9 million, or $0.30 per common share, compared to net income of $0.07 per commona 50% working interest share in both1,625 gross leasehold acres associated with two initial development blocks. As of March 31, 2024, we have participated in the priordrilling and year-ago quarters.

Net income for the current quarter included a one-time $6.0 million non-cash tax benefit related to passagecompletion of the Tax Cutsfirst development block which consisted of three gross (1.5 net ) wells. Following the completion of the second development block, we will have the right, but not the obligation, to elect to participate in additional development blocks. The Participation Agreement initially includes up to 80 gross drilling locations across twelve development blocks. Refer to Capital Expenditures below for a further discussion of Chaveroo drilling and Jobs Actcompletion activities since entering into the Participation Agreement.

Risks and uncertainties

The global economy was deeply impacted by the effects of 2017.

Our realizedthe novel coronavirus (“COVID-19”) pandemic and related efforts to mitigate the spread of the disease. These events led to crude oil price for the current quarter was $57.30 per barrel, the highest quarterly average since the quarter ended June 30, 2015.
We paid our seventeenth consecutive quarterly cash dividend on common shares, in the amount of $0.075 per share, and announced an increase in the quarterly dividend rateprices falling to $0.10 per share for the quarter ending March 31, 2018.
We ended the current quarter with $27.6 million of working capital, an increase of $3.2 million from the prior quarter, after paying $2.5 million in common stock dividends.

Projects

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

Delhi Field - Enhanced Oil Recovery Project

Our interests in the Delhi field consist of a 23.9% working interest (with associated 19.0% net revenue interest) and separate royalty interests of 7.2%. This yields a total net revenue interest of 26.2%.

Gross oil production at Delhi inhistoric lows during the second quarter of fiscal 2018 averaged 7,370 barrels2020 and remaining depressed through much of 2020. Beginning in 2021, the demand for oil per day ("BOPD"), or 1,932 BOPD net to our interests, a 6.6% increase from the prior quarter and a 2.8% decrease from the year-ago quarter. Oil production in the quarter increased as we put additional existing compression capacity in service and experimented with larger choke sizes to boost the injection of CO2. We also had very few days of scheduled and unscheduled facility downtime compared to the prior quarter. Lastly, we benefited from lower air temperatures, after the high heat of the summer adversely effected production levels.

Gross natural gas liquid ("NGL") sales for this quarter of production were 1,079 barrels of oil equivalent per day ("BOEPD"), or 283 BOEPD net to our interests, up slightly from 1,047 BOEPD in the prior quarter. NGL production rates in the prior quarter were impacted by both planned and unplanned downtime in the field and at the central production facilities. In early August, the plant was shut-in for four days to perform capital upgrades to the inlet of the recycle facility. Results from the NGL plant subsequent to completion of this project have been positive, with the plant operating at or near maximum capacity and efficiency. The NGL plant is accomplishing its primary objective of removing the lighter hydrocarbons (i.e. methane and ethane) to increase the purity of the CO2 recycle stream and improve the efficiency of the flood. Over time, this is expected to increase the recovery of crude oil in the field. The plant is also producing significant quantities of higher value NGL's for sale as well as providing methane and ethane feedstock to power the electric turbine.

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

During the extreme cold of January 2018, we experienced two weather-related disruptions to production in the field, including an extended outage at the NGL plant. These issues have been remedied and the field and NGL plant are producing at normal capacity.
Field operating expenses were $14.30 per barrel of oil equivalent ("BOE") in the current quarter compared to $15.06 in the prior quarter. Our total lease operating expenses in the Delhi field were $2.9 million in the current quarter, essentially unchanged from the prior quarter, and $0.6 million over the year-ago quarter. Our purchased CO2 costs increased to $1.3 million ($6.21 per BOE) from $1.1 million ($5.67 per BOE) in the prior quarter. Purchased CO2 volumes were approximately the same in the two periods, but our costs per Mcf increased as a result of higher realized oil prices in the field, which are directly tied to the price per Mcf for purchased CO2. Under our contract with the operator, purchased CO2 is priced at 1% of the realized oil price in the field per thousand cubic feet (“Mcf”) plus sales taxes of 8% and transportation costs of $0.20 per Mcf. Our other lease operating costs were $1.6 million, down from $1.8 million in the prior quarter.

2017 Tax Cuts and Jobs Act

On December 22, 2017, the U.S. government enacted comprehensive tax legislation under the title of the Tax Cuts and Jobs Act ("Tax Act"). The Tax Act includes a permanent reduction in our federal corporate income tax rate from 34% to 21%. It also provides more favorable tax deductions associated with capital investments and other significant changes to tax law. The Tax Act became effective upon passage, so our statutory rate for the current fiscal year ended June 30, 2018 is a blended rate of 27.55%. The permanent reduction in the federal corporate income tax rate resulted in a one-time non-cash income tax benefit of approximately $6.0 million related to the adjustment of our liability for deferred income taxes to the lower rate in the Tax Act. The accounting for the effects of the rate change on the Company’s deferred tax balances is complete and no provisional amounts were recorded.
 Three Months Ended 
 December 31,
 Six Months Ended 
 December 31,
 2017 2016 2017 2016
Income before income taxes4,824,637
 3,668,731
 7,355,491
 6,374,682
Income tax (benefit) provision (a)(5,052,211) 1,361,097
 (4,661,889) 2,250,273
Effective tax rate (a)(105)% 37% (63)% 35%

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

Income taxes are recorded in our financial statements based on our estimated annual effective income tax rate. The effective rates used in the calculation of our income tax expense were approximately 21% and 37% for the three months ended December 31, 2017 and 2016, respectively. Including the adjustment for the $6.0 million discrete benefit resulting from the revaluation of our deferred income tax liabilities, the effective rate for the quarter ended December 31, 2017 was a tax benefit of (105)% of income before income taxes.

For the six months ended December 31, 2017 and 2016 the effective rates used in the calculation of our income tax expense were approximately 20% and 35% , respectively. Including the adjustment for the $6.0 million discrete benefit resulting from the revaluation of our deferred income tax liabilities, the effective rate for the six months ended December 31, 2017 was a tax benefit of (63)% of income before income taxes.

Excluding the impact of the $6.0 million deferred tax adjustment, the effective tax rates for the three months and six months ended December 31, 2017 were lower than the corresponding prior periodsrecovered primarily as a result of the lower statutory tax rateroll-out of the COVID-19 vaccine and higher utilizationlessening of percentage depletionpandemic related government restrictions on individuals and businesses. During the current year, natural gas prices have declined primarily due to a warmer winter, and during the current quarter, oil prices have increased somewhat due to geopolitical factors and increased demand relative to supply.

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

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At times, we do maintain cash balances in excess of basis during the current year.


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

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

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

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

Liquidity and Capital Resources

We

As of March 31, 2024, we had $25.7 million and $23.0$3.1 million in cash and cash equivalents and $42.5 million outstanding on our Senior Secured Credit Facility compared to $11.0 million in cash and cash equivalents and no borrowings outstanding on our Senior Secured Credit Facility at December 31, 2017 and June 30, 2017, respectively.

In addition,2023. Our primary sources of liquidity and capital resources during the nine months ended March 31, 2024 were cash provided by operations as well as net borrowings under our Senior Secured Credit Facility. Our primary uses of liquidity and capital resources for the nine months ended March 31, 2024 were our SCOOP/STACK Acquisitions, cash dividend payments to our common stockholders, and development capital expenditures, primarily at Chaveroo oilfield where we haveparticipated in drilling three gross (1.5 net) wells. As of March 31, 2024, working capital was $7.6 million, a senior secured reserve-based credit facility (the "Facility") withdecrease of $1.3 million from working capital of $8.9 million as of June 30, 2023.

The Senior Secured Credit Facility has a maximum capacity of $50.0 million. The Facility had $10.0 million ofsubject to a borrowing base availabilitydetermined by the lender based on December 31, 2017the value of our oil and June 30, 2017, respectively. Effective February 1, 2018, thenatural gas properties. The Senior Secured Credit Facility has a current borrowing base and availability under theof $50.0 million, with $42.5 million drawn as of March 31, 2024. The Senior Secured Credit Facility was expanded to $40.0 million. There have been no borrowings under the Facility, which matures on April 11, 2019 and is secured by substantially all of the Company’s assets.

Any future borrowingsour oil and natural gas properties and matures on April 9, 2026.

Borrowings bear interest, at the Company'sour option, at either LIBORthe SOFR plus 2.75%2.80% or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%.  For the nine months ended March 31, 2024 and 2023, the weighted average interest on our borrowings was 8.13% and 5.25%, respectively.The Senior Secured Credit Facility contains covenants that requirerequiring the maintenance of (i) a total leverage ratio of not more than 3.03.00 to 1.0,1.00, (ii) a debt service coveragecurrent ratio of not less than 1.11.00 to 1.01.00, and (iii) a consolidated tangible net worth of not less than $40$40.0 million, each as defined in the Senior Secured Credit Facility. The FacilityIt also contains other customary affirmative and negative covenants, including a hedging covenant discussed below, and events of default. As of DecemberMarch 31, 2017, the Company was2024, we were in compliance with all covenants containedunder the Senior Secured Credit Facility.

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

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

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Table of Contents

Value, as defined in the Facility.

DuringNinth Amendment to the six months ended December 31, 2017,Senior Secured Credit Facility, to $95.0 million. We are required to enter into hedges on a rolling 12-month basis when the borrowings under the Senior Secured Credit Facility exceed 25% of the Margined Collateral Value. The required amount of hedged oil and natural gas production is related to the amount of borrowings outstanding. At each redetermination, our Margined Collateral Value takes into account the estimated value of our oil and natural gas properties, proved developed reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria.

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

On November 9, 2021, we entered into the Eighth Amendment to the Senior Secured Credit Facility. This amendment, among other things, increased the borrowing base to $50.0 million and our cash balance increased $2.7 million during that period. Asadded a hedging covenant whereby we must hedge a minimum of December 31, 2017, our working capital25% to 75% of future production on a rolling 12-month basis when 25% or more of the borrowing base is utilized. The hedging covenant was $27.6 million, an increase of $4.2 million over working capital of $23.4 million at June 30, 2017.


amended in the subsequent amendments, as discussed above.

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

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

We may choose to evaluate and pursueare pursuing new growth opportunities through acquisitions orand other transactions. WeIn addition to cash on hand, we have access to at least $40 millionthe undrawn portion of availabilitythe borrowing base available under our senior secured credit facility if required. In addition weSenior Secured Credit Facility, totaling $7.5 million as of March 31, 2024. We also have an effective shelf registration statement with Securities and Exchange Commissionthe SEC under which we may issue up to $500.0 million of new debt or equity securities. If we choose to pursue new growth opportunities, we would expect to use our internal resources of cash, working capital and borrowing capacity under our credit facility. It may also be advantageous for us to consider issuing additional equity as part of any potential transaction, but we have no specific plans to do so at this time.

Our other significant use of cash is our on-going dividend program. The Board of Directors instituted a cash dividend on our common stock in December 2013 and we2013. We have since paid seventeen42 consecutive quarterly dividends. Distribution of a substantial portion of free cash flow in excess of our operating and capital requirements through cash dividends and potential repurchases of our common stock remains a priority of our financial strategy, and it is our long termlong-term goal to increase our dividends over time, as appropriate. In February 2018,On May 6, 2024, the Board of Directors declared an increasea quarterly cash dividend of $0.12 per share of common stock to shareholders of record on June 14, 2024 and payable on June 28, 2024.

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

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

In November 2023, we entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan is effective until June 30, 2024, unless extended, renewed or terminated, and has a maximum authorized amount of $0.8 million over that period. We may alter the terms of the plan from $0.075 per sharetime to $0.10 per share, effective withtime to the dividend payment in March 2018. The Board reviewsextent we determine changes are necessary to achieve the quarterly dividend rate in lightintended objectives of our financial position and operations, forecasted results, including the outlook for oil and NGL prices, the timing

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Table of further expansion of Delhi development and other potential growth opportunities.Contents

Capital Budget - Delhi Field

repurchase program. During the sixthree and nine months ended DecemberMarch 31, 2017,2024, 0.1 million shares of the Company’s common stock have been repurchased under the plan at a cost of approximately $0.8 million, including incremental direct transaction costs. These shares were subsequently cancelled.

Capital Expenditures

During the nine months ended March 31, 2024, we incurred $1.4$9.4 million ofin capital expenditures, a majority of which was spent at Delhi. This spending included $0.4 million for capital upgrades to the recycle plant, $0.5 million for Phase V infrastructure, $0.4 million for CO2 conformance projectsChaveroo Field where we participated in the drilling and $0.1 million for other capital expenditures.

A twelve-well infillcompletion of three gross (1.5 net) wells. First production on the three gross wells at Chaveroo Field occurred at the beginning of February 2024. During the first fiscal quarter of 2024, we also participated in the drilling programand completion of two new wells in the Delhi field has been approvedField. Production of the Delhi wells came online in the first fiscal quarter of 2024 and is plannedproduced consistently in the second fiscal quarter.

Based on discussions with our operators, we expect capital workover projects to commence duringcontinue in all the quarter ended March 31, 2018. The infill program has a revised estimated net cost of $4.7 million, the majority of which is expectedfields. Overall, for fiscal year 2024, we expect budgeted capital expenditures to be incurred in the remainderrange of the current fiscal year. The program consists of five new CO2 injection wells and seven new production wells and targets productive oil zones$10.0 million to $12.0 million, which we believe are not being swept effectively by the current CO2 flood. It isexcludes any potential acquisitions. Our expected to both add production and increase ultimate recoveries above the current developed producing oil reserves. The operator estimates it will take up to five months to drill and complete all the wells.

We have also approved additional net capital expenditures for fiscal 2018 totaling $2.8year 2024 include the two new drilled wells at Delhi Field and three wells at Chaveroo Field, both of which are discussed above. As mentioned in Recent Developments, we closed three separate definitive agreements to purchase oil and natural gas properties in the SCOOP/STACK plays in central Oklahoma for a combined purchase price of $40.5 million for water injection, flowlines and other infrastructureafter taking into account preliminary post-close adjustments. Our budgeted capital expenditures discussed above also include capital projects associated with properties acquired in preparation for the Phase V pattern development. Approximately $0.5 million of these costs have been incurred as of December 31, 2017. In addition, we expect to continue to perform conformance workover projects and will likely incur additional maintenance capital expenditures. Such amounts cannot be estimated accurately at this time, but are not expected to be material to our financial position.
SCOOP/STACK Acquisitions.

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

Overview of Cash Flow Activities
Net cash provided by operating activitiescapital and, as needed, from operations was $9.1 million and $5.9 million for the six months ended December 31, 2017 and 2016, respectively. The $3.2 million increase in cash provided by operations between these two periods resulted from $7.9 million of higher net income and a $1.2 million increase in cash provided by operating assets and liabilities, partially offset by a $5.9 million decrease in non-cash expenses and other adjustments to reconcile net income to net cash provided by operations. This decrease includes a $6.0 million one-time adjustment ofborrowings under our deferred income tax liability to the lower corporate tax rate under the 2017 Tax Cuts and Jobs Act.
Net cash used in investing activities was $1.0 million and $8.3 million for the six months ended December 31, 2017 and 2016, respectively. The decrease in cash outflows was primarily due to $7.0 million of lower capital expenditures together with a $0.3 million decline in derivative settlement payments.
Net cash used by financing activities for the six months ended December 31, 2017 and 2016 was $5.4 million and $12.4 million, respectively. The $7.1 million decrease in cash used was principally due to $7.9 million disbursed in the prior fiscal to redeem our preferred stock, $0.3 million of pre-redemption preferred dividend payments, and a $0.1 million decline in treasury stock purchases, partially offset by an increase of $1.2 million in common share dividends paid as a result of increases in dividend rates per share.

Senior Secured Credit Facility.

Full Cost Pool Ceiling Test and Proved Undeveloped Reserves

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

Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated DD&Adepletion, depreciation, and amortization and related deferred taxes, are limited to (the full cost valuation “ceiling”): the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%; plus the cost of any properties not being amortized;, plus the lower of cost or fair value of unproved properties, included in costs being amortized; less theas adjusted for related income tax effect related to the differences between the book and tax basis of the properties.effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and natural gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average first day of the month price received for our petroleum products during the twelve month12-month period ending with the balance sheet date. The prices used in calculating our ceiling test as of March 31, 2024 were $77.64 per barrel of oil, $2.44 per MMBtu of natural gas and $29.88 per barrel of NGLs. As of March 31, 2024, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling. If commodity prices drop below the averageprice levels were to substantially decline from the past twelve months,12-month average first day of the month pricing levels as of March 31, 2024 and remain down for a prolonged period of time, our valuation ceiling over our capitalized costs may be reduced and adversely impact our ceiling tests in future ceiling test calculations would be adversely affected.quarters. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required in the future. Additionally, a 10% reduction in respective commodity prices at March 31, 2024, while all other factors remained constant, would not have generated an impairment. 

Overview of Cash Flow Activities

Nine Months Ended March 31, 

    

2024

    

2023

    

Change

Cash flows provided by operating activities

$

14,742

$

51,719

$

(36,977)

Cash flows used in investing activities

(52,141)

(4,265)

(47,876)

Cash flows provided by (used in) financing activities

29,432

(37,347)

66,779

Net increase (decrease) in cash and cash equivalents

$

(7,967)

$

10,107

$

(18,074)

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

Our proved undeveloped reserves at June

30 2017 included 544 MBOE

Table of reservesContents

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

Cash used in investing activities for the nine months ended March 31, 2024 increased $47.9 million compared to the nine months ended March 31, 2023 primarily due to the acquisition of our SCOOP/STACK properties in February 2024 together with an increase in capital expenditures related to the drilling and $3.2completion of three new wells in the Chaveroo Field. As of the quarter ended March 31, 2024, we have paid approximately $43.8 million for the SCOOP/STACK Acquisitions and have accrued estimated preliminary purchase price adjustments of $3.3 million related to net cash flows earned on the properties from the effective date to the closing date to arrive a net purchase price of $40.5 million.

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

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Results of Operations

Three Months Ended March 31, 2024 and 1,564 MBOE2023

We reported net income of reserves$0.3 million and $10.9$14.0 million for the three months ended March 31, 2024 and 2023, respectively. The following table summarizes the comparison of future development costs associated withfinancial information for the Phase V developmentperiods presented:

 

Three Months Ended

March 31, 

(in thousands, except per unit and per BOE amounts)

    

2024

2023

    

Variance

    

Variance %

Net income (loss)

$

289

$

13,957

$

(13,668)

(97.9)

%

Revenues:

Crude oil

14,538

11,799

2,739

23.2

%

Natural gas

5,860

21,598

(15,738)

(72.9)

%

Natural gas liquids

2,627

3,470

(843)

(24.3)

%

Total revenues

23,025

36,867

(13,842)

(37.5)

%

Operating costs:

Lease operating costs:

CO2 costs

1,035

1,821

(786)

(43.2)

%

Ad valorem and production taxes

1,458

1,642

(184)

(11.2)

%

Other lease operating costs

10,131

10,107

24

0.2

%

Depletion, depreciation, and accretion:

Depletion of full cost proved oil and natural gas properties

5,532

3,098

2,434

78.6

%

Accretion of asset retirement obligations

368

285

83

29.1

%

General and administrative expenses:

General and administrative

1,868

1,814

54

3.0

%

Stock-based compensation

549

453

96

21.2

%

Other income (expense):

Net gain (loss) on derivative contracts

(1,183)

270

(1,453)

(538.1)

%

Interest and other income

63

13

50

384.6

%

Interest expense

(518)

(32)

(486)

1,518.8

%

Income tax (expense) benefit

(157)

(3,941)

3,784

(96.0)

%

Production:

Crude oil (MBBL)

199

167

32

19.2

%

Natural gas (MMCF)

2,115

2,204

(89)

(4.0)

%

Natural gas liquids (MBBL)

104

104

-

%

Equivalent (MBOE)(1)

656

638

18

2.8

%

Average daily production (BOEPD)(1)

7,209

7,089

120

1.7

%

Average price per unit(2):

Crude oil (BBL)

$

73.06

$

70.65

$

2.41

3.4

%

Natural gas (MCF)

2.77

9.80

(7.03)

(71.7)

%

Natural Gas Liquids (BBL)

25.26

33.37

(8.11)

(24.3)

%

Equivalent (BOE)(1)

35.10

57.79

(22.69)

(39.3)

%

Average cost per unit:

Operating costs:

Lease operating costs:

CO2 costs

$

1.58

$

2.85

(1.27)

(44.6)

%

Ad valorem and production taxes

2.22

2.57

(0.35)

(13.6)

%

Other lease operating costs

15.44

15.84

(0.40)

(2.5)

%

Depletion of full cost proved oil and natural gas properties

8.43

4.86

3.57

73.5

%

General and administrative expenses:

General and administrative

2.85

2.84

0.01

0.4

%

Stock-based compensation

0.84

0.71

0.13

18.3

%

(1)Equivalent oil reserves are defined as six MCF of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.
(2)Amounts exclude the impact of cash paid or received on the settlement of derivative contracts since we did not elect to apply hedge accounting.

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Revenues

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

Lease Operating Costs

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

The following table summarizes CO2 costs per Mcf and recover reserves whichCO2 volumes for the three months ended March 31, 2024 and 2023. CO2 purchase costs are not believed to be effectively produciblefor the Delhi Field. Under our contract with the existing well configuration. Delhi Field operator, purchased CO2 is priced at 1% of the realized oil price in the field per MCF, plus sales taxes and transportation costs as per contract terms.

 

Three Months Ended

March 31, 

    

2024

    

2023

    

Variance

    

Variance %

CO2 costs per MCF

$

0.92

$

0.92

$

%

CO2 volumes (MMCF per day, gross)

52.1

91.7

(39.6)

(43.2)

%

The project includes both acceleration$0.8 million decrease in CO2 costs for the three months ended March 31, 2024 was primarily due to a 43.2% decrease in purchased CO2 volumes, which was primarily due to the suspension of productionCO2 purchases at the end of February 2024 due to maintenance on the CO2 pipeline. CO2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. We do not have any ownership in the CO2pipeline which is owned and operated by Denbury. On a per unit basis, CO2 costs were $1.58 per BOE and $2.85 per BOE for the three months ended March 31, 2024 and 2023, respectively.

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

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Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased $2.4 million or 78.6% from $3.1 million to $5.5 million for the three months ended March 31, 2024 primarily due to an increase in ultimate reserve recoverythe depletion rate. On a per unit basis, depletion expense was $8.43 per BOE and has been recorded as a proved undeveloped project.$4.86 per BOE for the three months ended March 31, 2024 and 2023, respectively. The infill project, which was increased from eight wells to twelve wells subsequent to the date of the reserve report, is expected to begin in the third quarter of fiscal 2018. The timingdepletion rate of our Phase V development is dependentunit of production calculation increased due to decreases in part onproved reserve volumes as well as increases in our depletable base due to our SCOOP/STACK Acquisitions and capital expenditures since March 31, 2023. Our proved reserves volumes have decreased since the results and CO2 requirement of the infill program. At present, we expectprior year period primarily due to begin this development in calendar 2019.


Three Months Ended December 31, 2017 and 2016
The following table sets forth certain financial information with respect to our oil and natural gas operations:
 Three Months Ended December 31,    
 2017 2016 Variance Variance %
Oil and gas production:       
  Crude oil revenues$10,185,635
 $8,529,817
 $1,655,818
 19.4 %
  NGL revenues881,276
 
 881,276
 n.m.
  Total revenues$11,066,911
 $8,529,817
 $2,537,094
 29.7 %
        
  Crude oil volumes (Bbl)177,767
 182,815
 (5,048) (2.8)%
  NGL volumes (Bbl)26,033
 
 26,033
 n.m.
Equivalent volumes (BOE)203,800
 182,815
 20,985
 11.5 %
        
  Crude oil (BOPD, net)1,932
 1,987
 (55) (2.8)%
  NGLs (BOEPD, net)283
 
 283
 n.m.
 Equivalent volumes (BOEPD, net)2,215
 1,987
 228
 11.5 %
        
  Crude oil price per Bbl$57.30
 $46.66
 $10.64
 22.8 %
  NGL price per Bbl33.85
 
 33.85
 n.m.
    Equivalent price per BOE$54.30
 $46.66
 $7.64
 16.4 %
        
CO2 costs
$1,265,582
 $1,041,741
 $223,841
 21.5 %
All other lease operating expenses1,648,930
 1,250,680
 398,250
 31.8 %
  Production costs$2,914,512
 $2,292,421
 $622,091
 27.1 %
  Production costs per BOE$14.30
 $12.54
 $1.76
 14.0 %
CO2 volumes (MMcf per day, gross)
69.7
 67.0
 2.7
 4.0 %
        
Oil and gas DD&A (a)$1,626,324
 $1,299,813
 $326,511
 25.1 %
Oil and gas DD&A per BOE$7.98
 $7.11
 $0.87
 12.2 %


n.m. Not meaningful.

(a) Excludes $7,544volumes produced combined with a reduction in the SEC prices used in calculating proved reserves since the prior year period.

General and $7,697 of other depreciationAdministrative Expenses

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

Stock-based Compensation Expense

Stock-based compensation expense for the three months ended DecemberMarch 31, 20172024 remained flat at $0.5 million for each period.

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Table of Contents

Net Gain (Loss) on Derivative Contracts

Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and 2016,natural gas prices. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the unaudited condensed consolidated statements of operations. The amounts recorded on the unaudited condensed consolidated statements of operations related to derivative contracts represent the (i) gains (losses) related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) gains (losses) on settlements of derivative contracts for positions that have settled or been realized. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized (gains) losses on our average realized prices for the periods presented. As a result of our SCOOP/STACK Acquisitions in the current quarter and our acquisitions during fiscal year 2022 and the corresponding borrowings on our Senior Secured Credit Facility, we were required by terms set in the Senior Secured Credit Facility to hedge a portion of our production. The increase in commodity prices since entering into the hedges and the continued increase in forward commodity prices resulted in a realized loss on hedges for the current quarter and an unrealized loss on the mark-to-market of our hedges, respectively.


Net Income Available to Common Stockholders. During As of March 31, 2024, we had $0.3 million derivative asset all of which was classified as current, and a $1.4 million derivative liability, all of which was classified as current.

Three Months Ended

March 31, 

(in thousands, except per unit and per BOE amounts)

    

2024

    

2023

    

Variance

    

Variance %

Realized gain (loss) on derivative contracts

$

(120)

$

465

$

(585)

(125.8)

%

Unrealized gain (loss) on derivative contracts

(1,063)

(195)

(868)

445.1

%

Total net gain (loss) on derivative contracts

$

(1,183)

$

270

$

(1,453)

(538.1)

%

Average realized crude oil price per BBL

$

73.06

$

70.65

$

2.41

3.4

%

Cash effect of oil derivative contracts per BBL

(0.60)

(0.60)

%

Crude oil price per BBL (including impact of realized derivatives)

$

72.46

$

70.65

$

1.81

2.6

%

Average realized natural gas price per MCF

$

2.77

$

9.80

$

(7.03)

(71.7)

%

Cash effect of natural gas derivative contracts per MCF

0.21

(0.21)

(100)

%

Natural gas price per MCF (including impact of realized derivatives)

$

2.77

$

10.01

$

(7.24)

(72.3)

%

Interest Expense

Interest expense increased $0.5 million for the three months ended DecemberMarch 31, 2017,2024 compared to the prior year period primarily due to borrowings drawn on our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions during the current period.

Income Tax (Expense) Benefit

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

35

Table of Contents

Nine Months Ended March 31, 2024 and 2023

We reported net income of $9.9$2.8 million or $0.30 per diluted share, on total revenues of $11.1 million. This compares to net income of $2.3 million, or $0.07 per diluted share, on revenues of $8.5and $35.1 million for the year-ago quarter.nine months ended March 31, 2024 and 2023, respectively. The $7.6following table summarizes the comparison of financial information for the periods presented:

 

Nine Months Ended

March 31, 

(in thousands, except per unit and per BOE amounts)

    

2024

    

2023

    

Variance

    

Variance %

Net income (loss)

$

2,845

$

35,051

$

(32,206)

(91.9)

%

Revenues:

Crude oil

38,913

40,062

(1,149)

(2.9)

%

Natural gas

17,943

58,816

(40,873)

(69.5)

%

Natural gas liquids

7,794

11,462

(3,668)

(32.0)

%

Total revenues

64,650

110,340

(45,690)

(41.4)

%

Operating costs:

Lease operating costs:

CO2 costs

4,241

6,027

(1,786)

(29.6)

%

Ad valorem and production taxes

4,008

7,001

(2,993)

(42.8)

%

Other lease operating costs

28,616

34,699

(6,083)

(17.5)

%

Depletion, depreciation, and accretion:

Depletion of full cost proved oil and natural gas properties

13,680

9,598

4,082

42.5

%

Accretion of asset retirement obligations

1,080

841

239

28.4

%

General and administrative expenses:

General and administrative

5,937

6,165

(228)

(3.7)

%

Stock-based compensation

1,585

1,155

430

37.2

%

Other income (expense):

Net gain (loss) on derivative contracts

(1,183)

513

(1,696)

(330.6)

%

Interest and other income

283

26

257

988.5

%

Interest expense

(584)

(404)

(180)

44.6

%

Income tax (expense) benefit

(1,174)

(9,938)

8,764

(88.2)

%

Production:

Crude oil (MBBL)

519

501

18

3.6

%

Natural gas (MMCF)

6,091

7,065

(974)

(13.8)

%

Natural gas liquids (MBBL)

295

325

(30)

(9.2)

%

Equivalent (MBOE)(1)

1,829

2,004

(175)

(8.7)

%

Average daily production (BOEPD)(1)

6,651

7,314

(663)

(9.1)

%

Average price per unit(2):

Crude oil (BBL)

$

74.98

$

79.96

$

(4.98)

(6.2)

%

Natural gas (MCF)

2.95

8.32

(5.37)

(64.5)

%

Natural Gas Liquids (BBL)

26.42

35.27

(8.85)

(25.1)

%

Equivalent (BOE)(1)

35.35

55.06

(19.71)

(35.8)

%

Average cost per unit:

Operating costs:

Lease operating costs:

CO2 costs

$

2.32

$

3.01

(0.69)

(22.9)

%

Ad valorem and production taxes

2.19

3.49

(1.30)

(37.2)

%

Other lease operating costs

15.65

17.31

(1.66)

(9.6)

%

Depletion of full cost proved oil and natural gas properties

7.48

4.79

2.69

56.2

%

General and administrative expenses:

General and administrative

3.25

3.08

0.17

5.5

%

Stock-based compensation

0.87

0.58

0.29

50.0

%

(1)Equivalent oil reserves are defined as six MCF of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.
(2)Amounts exclude the impact of cash paid or received on the settlement of derivative contracts since we did not elect to apply hedge accounting.

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Table of Contents

Revenues

Crude oil, natural gas and NGL revenues were $64.7 million earnings increase reflectsand $110.3 million for the nine months ended March 31, 2024 and 2023, respectively. The decrease in revenues is primarily due to the decrease in our average realized price per BOE coupled with a $2.5 million revenue increase, a $6.4 million declinedecrease in income taxes primarily attributable toour sales volumes. Our average realized commodity price (excluding the impact of derivative contracts) for the 2017 Tax Cutsnine months ended March 31, 2024 decreased approximately $19.71 per BOE, or 35.8%, over the prior year period. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and Jobs Act,supply, as impacted by overall economic activity, weather, inventory storage levels, basis differentials and other factors. Realized natural gas prices decreased 64.5% from the prior year period, which was the largest portion of the driver of the decrease in revenues. This was partially offset by $1.4 millionattributed to the prior year period benefit of higher operating expenses.

Oil and Gas Revenues. Revenues increased 30%strong natural gas price differentials received at the Jonah Field where we realized an average natural gas price of $12.99 per MCF in the prior year period compared to $11.1 million$4.16 in the current year period. Average daily equivalent production decreased 9.1% from 7,314 BOEPD in the prior year period to 6,651 BOEPD in the current period as a result of 11.5% increasenatural production declines in our properties combined with operational issues and downtime at our Barnett Shale property. We began experiencing production declines and downtime in April 2023 at Barnett. Production declines were primarily related to compression issues due to excessive heat, downtime in the gathering and processing system, pipeline rerouting and optimization, and our operator’s decision to temporarily shut-in certain low margin wells. As of March 31, 2024, the midstream issues have been moderated, but due to low natural gas prices the shut-in wells remain offline which has continued to negatively impact production volumes. The overall decrease in production was partially offset by the acquisitions of non-operated working interests in the SCOOP/STACK in February 2024 and first production at our wells in the Chaveroo Field in early February 2024, which collectively increased production for the nine months ended March 31, 2024 by approximately 340 BOEPD.

Lease Operating Costs

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

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

 

Nine Months Ended

March 31, 

    

2024

    

2023

    

Variance

    

Variance %

CO2 costs per MCF

$

0.97

$

1.01

$

(0.04)

(4.0)

%

CO2 volumes (MMCF per day, gross)

67.0

90.8

(23.8)

(26.2)

%

The $1.8 million decrease in CO2 costs for the nine months ended March 31, 2024 was primarily due to a 26.2% decrease in purchased CO2 volumes combined with a 16% increase4.0% decrease in CO2 costs per MCF, which was driven by a decrease in our average realized oil price and NGL prices from $46.66 per equivalent barrelthe suspension of CO2 purchases at the end of February 2024 due to $54.30 per equivalent barrelmaintenance on the CO2 pipeline. CO2 volumes injected were also reduced compared to prior year period due to a reduction in CO2 purchase nominations and higher ambient temperatures in the current quarter. All of our revenues forDelhi Field during the current and year-ago quarters came from the Delhi field. Net Delhi oil production volumes of 1,932 BOPD decreased 55 BOPD from the year-ago quarter, as a number of highly successful conformance and production enhancement operations infiscal year. In the prior year stabilized at lower ratesperiod, CO2 purchase nominations were higher to compensate for reduced reservoir pressure. CO2 purchases provide approximately 20% of the injected volumes in the current quarter. Net NGL production averaged 283 BOEPDfield and the field’s recycle facilities provide the other 80%. We do not have any ownership in the current quarter, at an average sales price of $33.85CO2 pipeline which is owned and operated by Denbury.  On a per barrel. Thereunit basis, CO2 costs were no NGL sales in the year-ago quarter as NGL plant production began in January 2017.

Production Costs. Production costs$2.32 per BOE and $3.01 per BOE for the current quarter were $2.9 million, a $0.6nine months ended March 31, 2024 and 2023, respectively.

Other lease operating costs decreased $6.1 million, or 27%17.5%, increase fromcompared to the year-ago quarter,prior year period primarily due to to higher CO2 costs andlower production combined with the incrementallower commodity price environment. On a per unit basis, other lease operating costs of the NGL plant that commenced operations in January 2017. CO2 costs increased $0.2 million, or 21%, duedecreased to a higher purchase cost$15.65 per Mcf, which is derived from the realized field oil price, together with 4% increase in purchase volumes. Average gross purchased CO2 volumes increased from 67.0 MMcf per day in the year-ago quarter to 69.7 MMcf per dayBOE for the current quarter. Other production costs, which include incremental costs of the NGL plant, power, chemicals, repairs and maintenance, labor and overhead, increased $0.4 million, or 32%,nine months ended March 31, 2024 from the year-ago quarter. Virtually all of this increase was attributable to the NGL plant. Production costs per equivalent barrel in the current quarter were $14.30 per BOE on total production volumes, compared to $15.06$17.31 per BOE in the year-ago quarter. The largest decrease in operating costs is at our Barnett Shale properties and the Delhi Field. At the Barnett Shale,


37

Calculated solely on our

Table of Contents

significant cost savings efforts are being prioritized due to the lower realized natural gas prices and the shut-in of certain low margin wells at current natural gas prices. We are incurring lower operating costs in all cost categories, especially lower water hauling costs and lower gathering, transportation and processing charges. At Delhi working interest volumes, production costs were $18.75Field, we have seen lower electricity charges due to lower commodity prices.

Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased $4.1 million or 42.5% from $9.6 million to $13.7 million for the nine months ended March 31, 2024 primarily due to an increase in the depletion rate. On a per unit basis, depletion expense was $7.48 per BOE of which $8.55and $4.79 per BOE was COcost. These costs per equivalent barrel excludefor the nine months ended March 31, 2024 and 2023, respectively. The depletion rate of our unit of production calculation increased due to decreases in proved reserve volumes fromas well as increase in our royalty interestsdepletable base due to our SCOOP/STACK Acquisitions and capital expenditures since the prior year period. Our proved reserves volumes have decreased since the prior year period primarily due to oil and natural gas volumes produced, combined with a reduction in the Delhi field, which bear almost no production costs, and are therefore higher thanSEC prices used for calculating proved reserves since the rates per barrel on our total production volumes.

prior year period.

General and Administrative Expenses (“G&A”). G&A

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

Stock-based Compensation Expense

Stock-based compensation expense for the nine months ended March 31, 2024 increased $0.4 million or 34%, to $1.7$1.6 million compared to $1.2 million for the three months ended December 31, 2017prior year period. The increase is primarily due to the addition of new personnel, including our CEO and COO added since the prior year period and the associated new awards granted during the current year period.

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Table of Contents

Net Gain (Loss) on Derivative Contracts

Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the unaudited condensed consolidated statements of operations. The amounts recorded on the unaudited condensed consolidated statements of operations related to derivative contracts represent the (i) gains (losses) related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) gains (losses) on settlements of derivative contracts for positions that have settled or been realized. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized (gains) losses on our average realized prices for the periods presented. As a result of $0.2 millionour SCOOP/STACK Acquisitions in the current quarter and our acquisitions during fiscal year 2022 and the corresponding borrowings on our Senior Secured Credit Facility, we were required by terms set in the Senior Secured Credit Facility to hedge a portion of higher non-cash stock compensation expense, $0.1 million for litigation costsour production. The increase in commodity prices since entering into the hedges and $0.1 million for due diligence costs associated with property evaluations.

Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A increased $0.3 million, or 25%, to $1.6 millionthe continued increase in forward commodity prices resulted in a realized loss on hedges for the current quarter compared toand an unrealized loss on the year-ago period primarilymark-to-market of our hedges, respectively. As of March 31, 2024, we had $0.3 million derivative asset all of which was classified as current, and a result$1.4 million derivative liability, all of higher full cost amortization, reflecting an 11% increase in production to 203,800 BOE, together with a 12% higher amortization rate of $7.98 per BOE. The higher rate is principally due towhich was classified as current.

Nine Months Ended

March 31, 

(in thousands, except per unit and per BOE amounts)

    

2024

    

2023

    

Variance

    

Variance %

Realized gain (loss) on derivative contracts

$

(120)

$

(1,481)

$

1,361

(91.9)

%

Unrealized gain (loss) on derivative contracts

(1,063)

1,994

(3,057)

(153.3)

%

Total net gain (loss) on derivative contracts

$

(1,183)

$

513

$

(1,696)

(330.6)

%

Average realized crude oil price per BBL

$

74.98

$

79.96

$

(4.98)

(6.2)

%

Cash effect of oil derivative contracts per BBL

(0.23)

(0.49)

0.26

(53.1)

%

Crude oil price per BBL (including impact of realized derivatives)

$

74.75

$

79.47

$

(4.72)

(5.9)

%

Average realized natural gas price per MCF

$

2.95

$

8.32

$

(5.37)

(64.5)

%

Cash effect of natural gas derivative contracts per MCF

(0.17)

0.17

(100)

%

Natural gas price per MCF (including impact of realized derivatives)

$

2.95

$

8.15

$

(5.20)

(63.8)

%

Interest Expense

Interest expense increased development costs.


Six Months Ended December 31, 2017 and 2016
The following table sets forth certain financial information with respect to our oil and natural gas operations:
 Six Months Ended December 31,    
 2017 2016 Variance Variance %
Oil and gas production:       
  Crude oil revenues$18,014,890
 $16,123,672
 $1,891,218
 11.7 %
  NGL revenues1,589,892
 89
 1,589,803
 n.m.
  Natural gas revenues
 (4) 4
 n.m.
  Total revenues$19,604,782
 $16,123,757
 $3,481,025
 21.6 %
        
  Crude oil volumes (Bbl)344,504
 360,817
 (16,313) (4.5)%
  NGL volumes (Bbl)51,279
 4
 51,275
 n.m.
  Natural gas volumes (Mcf)
 16
 (16) n.m.
Equivalent volumes (BOE)395,783
 360,824
 34,959
 9.7 %
        
  Crude oil (BOPD, net)1,872
 1,961
 (89) (4.5)%
  NGLs (BOEPD, net)279
 
 279
 n.m.
  Natural gas (BOEPD, net)
 
 
 n.m.
 Equivalent volumes (BOEPD, net)2,151
 1,961
 190
 9.7 %
        
  Crude oil price per Bbl$52.29
 $44.69
 $7.60
 17.0 %
  NGL price per Bbl31.00
 22.25
 8.75
 39.3 %
  Natural gas price per Mcf
 (0.25) 0.25
 n.m.
    Equivalent price per BOE$49.53
 $44.69
 $4.84
 10.8 %
        
CO2 costs
$2,353,843
 $2,119,874
 $233,969
 11.0 %
All other lease operating expenses3,452,255
 2,517,188
 935,067
 37.1 %
  Production costs$5,806,098
 $4,637,062
 $1,169,036
 25.2 %
  Production costs per BOE$14.67
 $12.85
 $1.82
 14.2 %
        
CO2 volumes (MMcf per day, gross)
69.5
 70.4
 (0.9) (1.3)%
        
Oil and gas DD&A (a)$3,137,205
 $2,565,450
 $571,755
 22.3 %
Oil and gas DD&A per BOE$7.93
 $7.11
 $0.82
 11.5 %
n.m. Not meaningful.

(a) Excludes $15,206and $15,499 of other depreciation and amortization expense for the six months ended December 31, 2017 and 2016, respectively.

Net Income Available to Common Stockholders. During the six months ended December 31, 2017, we generated net income of $12.0 million, or $0.36 per diluted share, on total revenues of $19.6 million. This compares to net income of $2.9 million, or $0.09 per diluted share, on revenues of $16.1$0.2 million for the sixnine months ended DecemberMarch 31, 2016.  The $9.1 million earnings increase reflects higher revenues of $3.5 million, an income tax decrease of $6.9 million primarily attributable2024 compared to the impact of Tax Cuts and Jobs Act, and a $1.2 million decrease in allocated net income to holders of preferred shares retired in November 2016, partially offset by $2.5 million of higher operating expenses.
Oil and Gas Revenues. Revenues increased 22% to $19.6 million as a result of a 10% increase in production volumes over the prior year period together with a 11% increase in realized prices from $44.69 per equivalent barrelprimarily due to $49.53 per equivalent barrel. All ofborrowings drawn on our revenues inSenior Secured Credit Facility to finance our SCOOP/STACK Acquisitions during the current fiscal year came fromyear.

Income Tax (Expense) Benefit

For the Delhi field, as well as virtually allnine months ended March 31, 2024, we recognized income tax expense of our revenues from$1.2 million on net income before income taxes of $4.0 million compared to income tax expense of $9.9 million on net income before income taxes of $45.0 million for the prior year. Net Delhi oil production volumes of 1,872 BOPD decreased 89 BOPD fromnine months ended March 31, 2023. The effective tax rates were 29.2% and 22.1% for three months ended March 31, 2024 and 2023, respectively. The effective tax rate increased compared to the prior year period. Net NGL production averaged 279 BOEPD, at an average price of $31.00 per barrel. There were no NGL sales in the year-ago period as NGL plant production beganprojected state income taxes have become a larger component of our overall income tax expense during the period.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements. The preparation of financial statements in January 2017.

Production Costs. Production costs for the current year period were $5.8 million, a $1.2 million, or 25%, increase from the same period a year ago, primarily due to higher CO2 costs and the incremental operating costs of the NGL plant that commenced operations in January 2017. CO2 costs increased $0.2 million, or 11%, due to higher purchase cost per Mcf, which is derived from the realized field oil price, partially offset by a slight 1% decline in purchase volumes. Average gross purchased CO2 volumes decreased from 70.4 MMcf per day in the year-ago period to 69.5 MMcf per day for the current year. Other production costs, which include incremental costs of the NGL plant, power, chemicals, repairs and maintenance, labor and overhead, increased $0.9 million, or 37%, from the year-ago period. Virtually all of this increase was attributable to the NGL plant. Production costs per equivalent barrel in the current period were $14.67 per BOE on total production volumes, compared to $12.85 in the prior year period.

Calculated solely on our Delhi working interest volumes, production costs were $19.24 per BOE, of which $8.19 per BOE was COcost. These costs per equivalent barrel exclude production volumes from our royalty interests in the Delhi field, which bear almost no production costs, and are therefore higher than the rates per barrel on our total production volumes.
General and Administrative Expenses (“G&A”). G&A expenses increased $0.8 million, or 31%, to $3.2 million for the six months ended December 31, 2017. The increase in expense included $0.4 million of non-cash stock-based compensation expense, $0.1 million of severance costs, $0.1 million of litigation expense, $0.1 million of due diligence costs associatedaccordance with property evaluations, and $0.1 million of higher board of director expenses.
Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A increased $0.6 million, or 22%, to $3.2 million for the current period compared to the year-ago period primarily due to higher full cost amortization, reflecting a 10% increase in production to 395,783 BOE, together with a 12% higher amortization rate of $7.93 per BOE. The higher rate is principally due to increased development costs.
Other Economic Factors
Inflation. Although the general inflation rateaccounting principles generally accepted in the United States of America requires that we select certain accounting policies and make estimates and assumptions that affect the reported amounts of the assets, liabilities, and disclosures of contingent assets and liabilities as measured byof the Consumer Price Index anddate of the Producer Price Index, has been relatively low in recent years, the oil and gas industry has experienced unusually volatile price movements in commodity prices, vendor goods and oilfield services. Prices for drilling and oilfield services, oilfield equipment, tubulars, labor, expertise and other services impact our lease operating expenses and our capital expenditures. During fiscal 2018 to date, we have seen a firming of prices for operating and capital costs as a result of improving demand and a closer balance with the supply of goods and services in the industry. Product prices, operating costs and development costs may not always move in tandem.
Known Trends and Uncertainties.  General worldwide economic conditions,sheet as well as economic conditionsthe reported amounts of revenues and expenses during the reporting period. These policies, together with our estimates, have a significant effect on our unaudited condensed

39

Table of Contents

consolidated financial statements. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the oil and gas industry specifically, continue to be uncertain and volatile. Concerns over uncertain future economic growth are affecting numerous industries and companies, as well as consumers, which impact demand for crude oil and natural gas. If the supply of crude oil and natural gas exceeds demand in the future, it may put downward pressure on crude oil and natural gas prices, thereby lowering our revenues, profits, cash flow and working capital going forward. While we realized higher average oil prices in the quarter than any period since the quarterfiscal year ended June 30, 2015, there can be no assurance that such prices will continue to prevail or trend upward.

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

Off Balance Sheet Arrangements
The Company had no off-balance sheet arrangements to report for the quarter ended December 31, 2017.
2023.

ITEM

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Information about market   Quantitative and Qualitative Disclosures About Market Risks

Derivative Instruments and Hedging Activity

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

Commodity Price Risk
Our most significant market riskproduction is the pricing for crudesold. When oil, natural gas, and NGL's.natural gas liquids prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable. If energyunpredictable, therefore we monitor commodity prices decline significantly, our revenues and cash flow would significantly decline. In addition, a non-cash write-downto identify the potential need for the use of ourderivative financial instruments to provide partial protection against declines in oil and natural gas properties couldprices. We do not enter into derivative contracts for speculative trading purposes. In accordance with our Senior Secured Credit Facility, we may be required to enter into hedges if we meet certain utilization levels of the borrowing base under full cost accounting rules if future oilthe credit facility. We intend to remain in compliance with these covenants and gas commodity prices sustained a significant decline. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital, as, if and when needed. We may usewill enter into derivative instruments to manage our exposure to commodity price riskcontracts from time to time basedto meet the requirements. Additionally, depending on market conditions, financial and other considerations we may enter into additional hedges to meet our objectives of increasing value to shareholders.

We are exposed to market risk on our assessmentopen derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competitive market makers. For the derivative contracts settled during fiscal 2024 and 2023, we did not post collateral. We account for our derivative activities under the provisions of such risk.

ASC 815, Derivatives and Hedging, (“ASC 815”). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 7, “Derivatives” to our unaudited condensed consolidated financial statements for more details.

Interest Rate Risk

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

ITEM

Item 4. CONTROLS AND PROCEDURES

Controls and Procedures

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

As required by Securities and Exchange CommissionSEC Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of the Company’sour management, including our ChiefPrincipal Executive Officer and ChiefPrincipal Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15d-15(e)15(d)-15(e)) as of the end of the quarter covered by this report. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. Based on the foregoing, our ChiefPrincipal Executive Officer and ChiefPrincipal Financial Officer concluded that as of DecemberMarch 31, 20172024 our disclosure controls and procedures are effective in ensuring that the information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange CommissionSEC rules and forms.

40

Table of Contents

Under the supervision and with the participation of the Company’sour management, including its Chiefour Principal Executive Officer and ChiefPrincipal Financial Officer, during the quarter ended DecemberMarch 31, 2017,2024, we have determined that there hashave been no changes in our internal controlscontrol over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal controlscontrol over financial reporting.



PART II -

Part II. OTHER INFORMATION

ITEM

Item 1. LEGAL PROCEEDINGS

We are involvedLegal Proceedings

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


ITEM

Item 1A.   RISK FACTORS

Risk Factors

Our Annual Report on Form 10-K for the year ended June 30, 20172023 includes a detailed description of our risk factors. There have been no material changes to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended June 30, 2017.

ITEM

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

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

Issuer Purchases of Equity Securities

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

The table below summarizes information about the Company's purchases of its equity securities during the quarterthree months ended DecemberMarch 31, 2017.2024.

(c) Total number

(d) Maximum dollar value

(a) Total number

of shares

of shares that may yet be

of shares

purchased as part

purchased under the

purchased and

(b) Average price

of public announced

plans or programs

Period

received (1)

paid per share (1)

plans or programs(2)

(in thousands)(2)

January 2024

400

$

5.50

400

$

21,150

February 2024

150,799

5.35

140,272

20,403

March 2024

741

5.90

20,403

Period 
(a) Total Number of
Shares
Purchased (1)
 
(b) Average Price
Paid per Share(1)
 
(c) Total Number of Shares Purchased as Part
of Publicly Announced Plans or Programs (2)
 
(d) Maximum 
Dollar Value
of Shares that
May Yet Be Purchased
Under the Plans or
Programs (2)
October 2017 2,471 $7.03 Not applicable $3.4 million
November 2017 29,001 $7.20 Not applicable $3.4 million
December 2017 8,262 $7.10 Not applicable $3.4 million
Total 39,734 $7.17 Not applicable $3.4 million
(1)During the three months ended March 31, 2024, all of the shares received outside of publicly announced plans or programs were surrendered by employees in exchange for the payment of tax withholding upon the vesting of restricted stock awards.
(2)On September 8, 2022, the Company’s Board of Directors approved a share repurchase program, under which the Company is authorized to repurchase up to $25.0 million of its common stock in the open market through December 31, 2024. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will depend on a variety of factors, including management’s assessment of the intrinsic value of the Company’s shares, the market price of the Company's common stock, the Company’s capital needs and resources, general market and economic conditions, and applicable legal requirements. The value of shares authorized for repurchase by the Company's Board of Directors does not require the Company to repurchase such shares or guarantee that such shares will be repurchased, and the program may be suspended, modified, or discontinued at any time without prior notice. In November 2023, the Company entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan is effective until June 30, 2024, unless extended, renewed or terminated by the Company, and has a maximum authorized amount of $0.8 million over that period. The Company may alter the terms of the plan from time to time to the extent it determines changes are necessary to achieve the intended objectives of the repurchase program.

(1)During the current quarter the Company received shares

41

ITEM

Item 3. DEFAULTS UPON SENIOR SECURITIES

Defaults Upon Senior Securities

Not applicable.


Applicable.

ITEM

Item 4. MINE SAFETY DISCLOSURES

Mine Safety Disclosures

Not applicable.


Applicable.

ITEM

Item 5. OTHER INFORMATION

Other Information

None.


ITEM

Item 6. EXHIBITS

A.Exhibits

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

3.1

Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 of our Quarterly Report on Form 10-Q filed February 8, 2023).

3.3

Amended and Restated Bylaws (incorporated by reference to Exhibit 3.3 of our Annual Report on Form 10- filed September 13, 2023)

4.1

10.11*


4.2
10.1

31.1

10.12*


Purchase and Sale Agreement, dated February 12, 2024, between Evolution Petroleum Corporation and Red Sky Resources IV, LLC

10.13*

Purchase and Sale Agreement, dated February 12, 2024, between Evolution Petroleum Corporation and Coriolis Energy Partners I, LLC

10.2.11*

Amendment to the Credit Agreement dated February 12, 2024 between Evolution Petroleum Corporation and MidFirst Bank

31.1**

Certification of ChiefPrincipal Executive Officer pursuantPursuant to Rule 13a-14(a) or Rule 15d-14(a) under15D-14 of the Securities Exchange Act of 1934, as amended.Amended as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2

31.2**


32.1

32.1**


32.2

32.2**


101.INS

101.INS*


Inline XBRL Instance Document

101.SCH

101.SCH*


Inline XBRL Taxonomy Extension Schema Document

101.CAL

101.CAL*


Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF

101.DEF*


Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB

101.LAB*


Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE

101.PRE*


Inline XBRL Taxonomy Extension Presentation Linkbase Document

104*

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

* Attached hereto.

** Furnished herewith.


42

SIGNATURES

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

EVOLUTION PETROLEUM CORPORATION
(Registrant)

Evolution Petroleum Corporation

Date: May 8, 2024

By:

/s/ KELLY W. LOYD

By:

/s/ RANDALL D. KEYS
Randall D. Keys

Kelly W. Loyd

President and Chief Executive Officer (Principal Executive Officer) and Director

By:

/s/ RYAN STASH

Date: February 8, 2018

Ryan Stash

Senior Vice President and Chief Financial Officer (Principal Financial Officer) and Treasurer


43


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