SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended December 31, 2017
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☐ | 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 (Exact name of registrant as specified in its charter) Nevada 41-1781991 (State or other jurisdiction of (IRS Employer Identification No.) 1155 Dairy Ashford Road, Suite 425, Houston, Texas77079 (Address of principal executive offices and zip code) (713) 935-0122 (Registrant’s telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Trading Symbol(s) Name of Each Exchange On Which Registered Common Stock, $0.001 par value EPM NYSE American Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes: Indicate by check mark whether the registrant has submitted electronically 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 Large accelerated filer ☐ Accelerated filer ☒ Non-accelerated filer ☐ Smaller reporting company ☒ Emerging growth company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.). Yes: At February 2, 2024, 33,456,330 shares EVOLUTION PETROLEUM CORPORATION 2 4 4 4 5 6 7 8 Management’s Discussion and Analysis of Financial Condition and Results of Operations 23 37 37 38 38 38 39 39 39 39 40 41 We use the terms, “EPM,” “Company,” “we,” “us,” and “our” to refer to Evolution Petroleum Corporation, and 1 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: 2 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: 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 Part I. FINANCIAL INFORMATION Item 1. Condensed Consolidated Financial Statements (Unaudited) EVOLUTION PETROLEUM CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (In thousands, except share and per share amounts) December 31, 2023 June 30, 2023 Assets Current assets Cash and cash equivalents $ 8,460 $ 11,034 Receivables from crude oil, natural gas, and natural gas liquids revenues 10,119 7,884 Prepaid expenses and other current assets 2,569 2,277 Total current assets 21,148 21,195 Property and equipment, net of depletion, depreciation, and impairment Oil and natural gas properties—full-cost method of accounting: Oil and natural gas properties, subject to amortization, net 100,111 105,781 Oil and natural gas properties, not subject to amortization 3,370 — Total property and equipment, net 103,481 105,781 Other assets 1,337 1,341 Total assets $ 125,966 $ 128,317 Liabilities and Stockholders' Equity Current liabilities Accounts payable $ 8,233 $ 5,891 Accrued liabilities and other 6,294 6,027 State and federal taxes payable — 365 Total current liabilities 14,527 12,283 Long term liabilities Deferred income taxes 6,161 6,803 Asset retirement obligations 17,738 17,012 Operating lease liability 101 125 Total liabilities 38,527 36,223 Commitments and contingencies (Note 9) Stockholders' equity Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 33,506,794 and 33,247,523 shares as of December 31, 2023 and June 30, 2023, respectively 34 33 Additional paid-in capital 40,920 40,098 Retained earnings 46,485 51,963 Total stockholders' equity 87,439 92,094 Total liabilities and stockholders' equity $ 125,966 $ 128,317 See accompanying notes to unaudited condensed consolidated 4 (In thousands, except per share amounts) Three Months Ended Six Months Ended December 31, December 31, 2023 2022 2023 2022 Revenues Crude oil $ 11,759 $ 13,100 $ 24,375 $ 28,263 Natural gas 6,531 17,370 12,083 37,218 Natural gas liquids 2,734 3,206 5,167 7,992 Total revenues 21,024 33,676 41,625 73,473 Operating costs Lease operating costs 12,358 15,041 24,241 34,157 Depletion, depreciation, and accretion 4,598 3,458 8,860 7,056 General and administrative expenses 2,502 2,581 5,105 5,053 Total operating costs 19,458 21,080 38,206 46,266 Income (loss) from operations 1,566 12,596 3,419 27,207 Other income (expense) Net gain (loss) on derivative contracts — 846 — 243 Interest and other income 104 7 220 13 Interest expense (34) (129) (66) (372) Income (loss) before income taxes 1,636 13,320 3,573 27,091 Income tax (expense) benefit (554) (2,933) (1,017) (5,997) Net income (loss) $ 1,082 $ 10,387 $ 2,556 $ 21,094 Net income (loss) per common share: Basic $ 0.03 $ 0.31 $ 0.08 $ 0.63 Diluted $ 0.03 $ 0.31 $ 0.08 $ 0.62 Weighted average number of common shares outstanding: Basic 32,693 33,174 32,676 33,154 Diluted 32,900 33,394 32,940 33,356 See accompanying notes to unaudited condensed consolidated 5 EVOLUTION PETROLEUM CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (In thousands) Six Months Ended December 31, 2023 2022 Cash flows from operating activities: Net income (loss) $ 2,556 $ 21,094 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depletion, depreciation, and accretion 8,860 7,056 Stock-based compensation 1,036 702 Settlement of asset retirement obligations — (71) Deferred income taxes (642) (355) Unrealized (gain) loss on derivative contracts — (2,189) Accrued settlements on derivative contracts — (919) Other 3 (4) Changes in operating assets and liabilities: Receivables from crude oil, natural gas, and natural gas liquids revenues (2,239) 8,113 Prepaid expenses and other current assets (274) (316) Accounts payable and accrued liabilities 2,443 (5,398) State and federal income taxes payable (365) 56 Net cash provided by operating activities 11,378 27,769 Cash flows from investing activities: Acquisition of oil and natural gas properties — (31) Capital expenditures for oil and natural gas properties (5,705) (2,886) Net cash used in investing activities (5,705) (2,917) Cash flows from financing activities: Common stock dividends paid (8,034) (8,085) Common stock repurchases, including stock surrendered for tax withholding (213) (87) Repayments of senior secured credit facility — (21,250) Net cash (used in) provided by financing activities (8,247) (29,422) Net increase (decrease) in cash and cash equivalents (2,574) (4,570) Cash and cash equivalents, beginning of period 11,034 8,280 Cash and cash equivalents, end of period $ 8,460 $ 3,710 Supplemental disclosures of cash flow information: Non-cash investing and financing transactions: Increase (decrease) in accrued capital expenditures for oil and natural gas properties $ (142) $ (768) See accompanying notes to unaudited condensed consolidated 6 EVOLUTION PETROLEUM CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (Unaudited) (In thousands) Additional Total Common Stock Paid-in Retained Treasury Stockholders' Shares Par Value Capital Earnings Stock Equity For the Three Months Ended December 31, 2023 Balances at September 30, 2023 33,440 $ 33 $ 40,465 $ 49,424 $ — $ 89,922 Issuance of restricted common stock 84 1 (1) — — — Common stock repurchases, including stock surrendered for tax withholding — — — — (108) (108) Retirements of treasury stock (17) — (108) — 108 — Stock-based compensation — — 564 — — 564 Net income (loss) — — — 1,082 — 1,082 Common stock dividends paid — — — (4,021) — (4,021) Balances at December 31, 2023 33,507 $ 34 $ 40,920 $ 46,485 $ — $ 87,439 For the Six Months Ended December 31, 2023 Balances at June 30, 2023 33,248 $ 33 $ 40,098 $ 51,963 $ — $ 92,094 Issuance of restricted common stock 288 1 (1) — — — Common stock repurchases, including stock surrendered for tax withholding — — — — (213) (213) Retirements of treasury stock (29) — (213) — 213 — Stock-based compensation — — 1,036 — — 1,036 Net income (loss) — — — 2,556 — 2,556 Common stock dividends paid — — — (8,034) — (8,034) Balances at December 31, 2023 33,507 $ 34 $ 40,920 $ 46,485 $ — $ 87,439 For the Three Months Ended December 31, 2022 Balances at September 30, 2022 33,546 $ 33 $ 42,811 $ 39,533 $ — $ 82,377 Issuance of restricted common stock 296 1 (1) — — — Forfeitures of restricted stock (26) — — — — — Common stock repurchases, including stock surrendered for tax withholding — — — — (61) (61) Retirements of treasury stock (8) — (61) — 61 — Stock-based compensation — — 494 — — 494 Net income (loss) — — — 10,387 — 10,387 Common stock dividends paid — — — (4,059) — (4,059) Balances at December 31, 2022 33,808 $ 34 $ 43,243 $ 45,861 $ — $ 89,138 For the Six Months Ended December 31, 2022 Balances at June 30, 2022 33,471 $ 33 $ 42,629 $ 32,852 $ — $ 75,514 Issuance of restricted common stock 375 1 (1) — — — Forfeitures of restricted stock (26) — — — — — Common stock repurchases, including stock surrendered for tax withholding — — — — (87) (87) Retirements of treasury stock (12) — (87) — 87 — Stock-based compensation — — 702 — — 702 Net income (loss) — — — 21,094 — 21,094 Common stock dividends paid — — — (8,085) — (8,085) Balances at December 31, 2022 33,808 $ 34 $ 43,243 $ 45,861 $ — $ 89,138 See accompanying notes to unaudited condensed consolidated financial statements. 7 EVOLUTION PETROLEUM CORPORATION NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 1. Financial Statement Presentation Nature of Operations. Evolution Petroleum Corporation The Company’s oil and natural gas properties consist of non-operated interests in the following areas: the Jonah Field in Sublette County, Wyoming, a natural gas and natural gas liquids producing field; the Williston Basin in North Dakota, producing oil and natural gas properties; the Barnett Shale located in North Texas, natural gas and natural gas liquids producing properties; the Hamilton Dome Field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir; the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana, a CO2 enhanced oil recovery project; the Chaveroo oilfield in Chaves and Roosevelt Counties of New Mexico; as well as small overriding royalty interests in four onshore Texas wells. Interim Financial Statements. Principles of Consolidation and Reporting. 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- 8 EVOLUTION PETROLEUM CORPORATION NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS producing leasehold, geologic and geophysical costs associated with leasehold or drilling interests, and exploration drilling costs. These costs are excluded until the project is evaluated and proved reserves are established or impairment is determined. The Company entered into a strategic partnership with PEDEVCO Corp. (“PEDEVCO”) on September 12, 2023, to jointly develop the Chaveroo oilfield in the Permian Basin in New Mexico (the “Chaveroo Field”). Per the terms of the participation agreement (the “Participation Agreement”) with PEDEVCO, Evolution paid for acreage associated with nine initial drilling locations totaling approximately $0.4 million. As of December 31, 2023, the Company recorded the payment for the initial acreage as unevaluated costs, excluded from the full cost pool. Refer to Note 3, “Property and Equipment,” for further details. Use of Estimates. The preparation of the Company’s unaudited condensed consolidated financial statements in conformity with GAAP requires Recently Issued Accounting In In Other accounting pronouncements that have recently been issued by the 9 EVOLUTION PETROLEUM CORPORATION NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 2. Revenue Recognition The Company’s revenues are primarily generated from its crude oil, natural gas and NGL production from the Jonah Field in Sublette County, Wyoming, the Williston Basin in North Dakota, the Barnett Shale located in North Texas, the Hamilton Dome Field in Wyoming, and the Delhi Field in Northeast Louisiana. Additionally, an overriding royalty interest retained in a past divestiture of Texas properties provides de minimis revenue. The following table disaggregates the Company’s revenues by major product for the three and six months ended December 31, 2023 and 2022 (in thousands): Three Months Ended Six Months Ended December 31, December 31, 2023 2022 2023 2022 Revenues Crude oil $ 11,759 $ 13,100 $ 24,375 $ 28,263 Natural gas 6,531 17,370 12,083 37,218 Natural gas liquids 2,734 3,206 5,167 7,992 Total revenues $ 21,024 $ 33,676 $ 41,625 $ 73,473 In the Jonah Field, the Company has elected to 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 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 The Company’s contractual performance obligations arise upon the 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 10 EVOLUTION PETROLEUM CORPORATION NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Differences between estimates and actual amounts received for product sales are recorded in the month that payments received from purchasers are remitted to the Company by field operators. Property and equipment as of December 31, 2023 and June 30, 2023 consisted of the following (in thousands): December 31, 2023 June 30, 2023 Oil and natural gas properties Property costs subject to amortization $ 199,526 $ 197,049 Property costs not subject to amortization 3,370 — Less: Accumulated depletion, depreciation, and impairment (99,415) (91,268) Oil and natural gas properties, net $ 103,481 $ 105,781 As of December 31, Upon signing the Participation Agreement, the Company paid total cash consideration of $0.4 million, which includes less than $0.1 million of capitalized transactions costs, in exchange for a 50% working interest share in the existing leases associated with two initial development blocks, or nine drilling locations. Following completion of the The Company uses the full cost method of accounting for its investments in oil and Additionally, the Company assesses all properties classified as unevaluated property on a quarterly basis for possible impairment. The Company assesses properties on an individual basis or as a group, if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and Depletion of oil and natural gas properties was $8.1 million and $6.5 million for the six months ended December 31, 2023 and 2022, respectively. During the six months ended December 31, At December 31, 2023, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month average for the 12-months ended December 31, 2023 of the West Texas Intermediate (“WTI”) crude oil spot price 11 EVOLUTION PETROLEUM CORPORATION NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS of $78.21 per barrel and Henry Hub natural gas spot price of $2.63 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $31.57, which was based on historical differentials to WTI as NGLs do not have any single comparable reference index price. Using these prices, at December 31, 2023 the cost center ceiling was higher than the capitalized costs of oil and natural gas properties, and as a result, no write-down was necessary. At December 31, 2022, the ceiling test value of the Company’s reserves was calculated based on the first-day-of the month average for the 12-months ended December 31, 2022 of the WTI crude oil spot price of $94.14 per barrel and Henry Hub natural gas spot price of $6.40 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $48.50, which was based on historical prices received as NGLs do not have any single comparable reference index price. Using these prices, at December 31, 2022 the cost center ceiling was higher than the capitalized costs of oil and natural gas properties, and as a result, no write-down was necessary. Note 4. Senior Secured Credit Facility On April 11, 2016, the Company The Company may elect, at its option, to prepay any borrowings outstanding under the Senior Secured Credit Facility without premium or penalty. Amounts outstanding under the Senior Secured Credit Facility are guaranteed by the Company’s direct and indirect subsidiaries and secured by a security interest in substantially all of the properties of the Company and its subsidiaries. Borrowings under the Senior Secured Credit Facility may be used for the acquisition and development of oil and natural gas properties, investments in cash flow generating properties complimentary to the production of oil and natural gas, and for letters of credit or other general corporate purposes. The Senior Secured Credit Facility contains certain events of default, including non-payment; breaches or representation and warranties; non-compliance with covenants; cross-defaults to material indebtedness; voluntary or involuntary bankruptcy; judgments and change in control. The Senior Secured Credit Facility also contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (i) a maximum total leverage ratio of not more than 3.00 to 1.00, (ii) a current ratio of not less than 1.00 to 1.00, and (iii) a consolidated tangible net worth of not less than $40.0 million, each as defined in the Senior Secured Credit Facility. As of December 31, 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 12 EVOLUTION PETROLEUM CORPORATION NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Secured Credit Facility will be based on the Margined Collateral Value, as defined in the agreement, to the extent it exceeds the borrowing base then in effect. Note 5. Income Taxes The Company files a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions. There were no unrecognized tax benefits, nor any accrued interest or penalties associated with unrecognized tax benefits during the periods presented in the unaudited condensed consolidated financial statements. The Company believes that it has appropriate support for the income tax positions taken and to be taken on the Company’s tax returns and that the accruals for tax liabilities are adequate for all open years based on its assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company’s federal and state income tax returns are open to audit under the statute of limitations for the fiscal years ended June 30, For six months ended December 31, 2023, the Company recognized income tax expense of $1.0 million and had an effective tax rate of 28.5% compared to income tax expense of $6.0 million and an effective tax rate of 22.1% for the six months ended December 31, 2022. The Company’s effective tax rate will typically differ from the statutory federal rate as a result of state income taxes, primarily in the states of Louisiana, North Dakota, and Texas, percentage depletion in excess of basis, and other permanent differences. For both periods, the respective statutory federal tax rate was 21%. Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets Note 6. Derivatives The Company is exposed to certain risks relating to its ongoing business operations, including commodity price risk and interest rate risk. In accordance with the Company’s strategy and the requirements under the Senior Secured Credit Facility (as discussed in Note 4, “Senior Secured Credit Facility”), it may hedge or may be required to hedge a varying portion of anticipated oil and natural gas production for future periods. Derivatives are carried at fair value on the unaudited condensed consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the unaudited condensed consolidated statements of operations for the period in which the change occurs. The Company’s hedge strategies and objectives may change significantly as its operational profile changes or as required under the Senior Secured Credit Facility. The Company does not enter into derivative contracts for speculative trading purposes. It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of June 30, 2023, all of the The Company has in the past, and may utilize in the future, commodity derivative contracts such as costless put/call collars and fixed-price swaps to hedge a portion of its anticipated future production. A costless collar consists of a sold 13 EVOLUTION PETROLEUM CORPORATION NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS call, which establishes a maximum price the Company will receive for the volumes under contract, and All derivative contracts are recorded Derivatives not designated Location of gain (loss) Three Months Ended Six Months Ended as hedging contracts recognized in income on December 31, December 31, under ASC 815 derivative contracts 2023 2022 2023 2022 Commodity contracts: Realized gain (loss) on derivative contracts Other income and expenses - net gain (loss) on derivative contracts $ — $ (224) $ — $ (1,946) Unrealized gain (loss) on derivative contracts Other income and expenses - net gain (loss) on derivative contracts — 1,070 — 2,189 Total net gain (loss) on derivative contracts $ — $ 846 $ — $ 243 The Company enters into an International Swap Dealers Association Master Agreements (“ISDA”) with each counterparty prior to a derivative contract with such counterparty. The ISDA is Note 7. Fair Value Measurement Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: Level 1—Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or Level 2—Other inputs that are observable directly or indirectly, such as quoted prices in markets that are not active or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Level 3—Unobservable inputs for which there are little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities. 14 EVOLUTION PETROLEUM CORPORATION NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Fair Value of Derivative Instruments. The Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s unaudited condensed consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable (Level 1) market corroborated (Level 2), or generally unobservable (Level 3). The Company classifies fair value balances based on observability of those inputs. As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgement, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any Other Fair Value Measurements. The following disclosure of the estimated fair value of financial instruments is made in The Company follows the provisions of ASC 820, for Note 8. Asset Retirement Obligations The Company’s ARO represents the estimated present value of the amount 15 EVOLUTION PETROLEUM CORPORATION NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following is a reconciliation of the December 31, 2023 Asset retirement obligations — beginning of period $ 17,067 Accretion of discount 712 Asset retirement obligations — end of period 17,779 Less: current asset retirement obligations (41) Long-term portion of asset retirement obligations $ 17,738 Note 9. Commitments and The Company is subject to various claims and contingencies in the Common Stock As of December 31, The Company began paying quarterly cash dividends on common stock in December 2013. Fiscal Year 2024 2023 Second quarter ended December 31, $ 0.120 $ 0.120 First quarter ended September 30, 0.120 0.120 On September 8, 2022, the Board of Directors approved a share repurchase program, 16 EVOLUTION PETROLEUM CORPORATION NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS In November 2023, the Company entered into a Rule 10b5-1 plan that authorizes a broker to During the six months ended December 31, The following Six Months Ended December 31, 2023 2022 Number of treasury shares acquired 29,236 12,049 Average cost per share $ 7.29 $ 7.19 Total cost of treasury shares acquired $ 213,015 $ 86,690 Expected Tax Treatment of Dividends For the fiscal year ended June 30, Stock-Based Incentive Plan The Evolution Petroleum Corporation 2016 Equity Incentive Plan The Company estimates the fair value of stock-based compensation awards on the grant date to provide the basis for future Time-Vested Restricted Stock Awards Time-vested restricted 17 EVOLUTION PETROLEUM CORPORATION NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS generally have one-year cliff vesting. For such awards, grant date fair value is based on market value of the Company’s common stock at the time of grant. This value is then amortized ratably over the service period. Performance-Based Restricted Stock Performance-based restricted stock awards and performance-based contingent stock units contain market-based vesting conditions based on Vesting of grants with performance-based vesting conditions is dependent on the During the six months ended December 31, 2023, the Company granted a total of During the six months ended December 31, 2022, the Company granted a total of 0.4 million equity awards that included 0.3 million time-vested restricted stock awards, 0.1 million performance-based restricted stock awards, and less than 0.05 million of performance-based contingent stock units. For performance-based awards granted during the six months ended December 31, 2023 and 2022, the assumptions used in Six Months Ended December 31, 2023 2022 Weighted average fair value of performance-based awards granted $ 3.58 $ 6.69 Risk-free interest rate 4.87% 3.91% to 4.44% Expected term in years 2.77 2.66 to 2.78 Expected volatility 55.0% 69.6% to 70.9% Dividend yield 7.4% 6.1% 18 Table of EVOLUTION PETROLEUM CORPORATION NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Unvested restricted stock awards as of Weighted Number of Average Restricted Grant-Date Award Type Shares Fair Value Time-vested awards 439,603 $ 6.61 Performance-based awards 278,688 5.46 Unvested at December 31, 2023 718,291 $ 6.16 The following table sets forth the Weighted Weighted Unamortized Average Number of Average Compensation Remaining Restricted Grant-Date Expense Amortization Shares Fair Value (In thousands) Period (Years) Unvested at June 30, 2023 595,414 6.48 $ 2,827 2.4 Time-vested shares granted 152,192 6.24 Performance-based shares granted 136,315 4.80 Vested (165,630) 6.26 Unvested at December 31, 2023 718,291 $ 6.16 $ 3,470 2.1 The following table sets forth Weighted Unamortized Average Number of Weighted Average Compensation Remaining Restricted Grant-Date Expense Amortization Stock Units Fair Value (In thousands) Period (Years) Unvested at June 30, 2023 96,398 $ 3.49 $ 195 1.9 Performance-based awards granted 102,239 1.95 Unvested at December 31, 2023 198,637 $ 2.70 $ 320 2.0 19 EVOLUTION PETROLEUM CORPORATION NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following table sets forth the computation of basic and diluted Three Months Ended Six Months Ended December 31, December 31, 2023 2022 2023 2022 Numerator Net income (loss) $ 1,082 $ 10,387 $ 2,556 $ 21,094 Undistributed earnings allocated to unvested restricted stock (24) (162) (51) (274) Net income (loss) for earnings per share calculation $ 1,058 $ 10,225 $ 2,505 $ 20,820 Denominator Weighted average number of common shares outstanding — Basic 32,693 33,174 32,676 33,154 Effect of dilutive securities: Unvested restricted stock awards 171 206 225 195 Unvested contingent restricted stock units 36 14 39 7 Weighted average number of common shares and dilutive potential common shares used in diluted earnings per share 32,900 33,394 32,940 33,356 Net income (loss) per common share — Basic $ 0.03 $ 0.31 $ 0.08 $ 0.63 Net income (loss) per common share — Diluted $ 0.03 $ 0.31 $ 0.08 $ 0.62 Unvested restricted stock awards (both time-vested and performance-based), totaling approximately 0.2 million and Unvested restricted stock awards (both time-vested and In addition, unvested performance-based restricted stock awards and unvested contingent restricted stock units that would not meet the performance criteria as of the period end are excluded from the computation of diluted earnings per common share. 20 EVOLUTION PETROLEUM CORPORATION NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 12. Additional Financial Statement Information Certain amounts on the unaudited condensed consolidated balance sheets are comprised of the following (in thousands): December 31, 2023 June 30, 2023 Prepaid expenses and other current assets: Other receivables $ 21 $ 18 Prepaid insurance 468 727 Prepaid federal and state income taxes 1,371 805 Carryback of EOR tax credit 347 347 Prepaid other 362 380 Total prepaid expenses and other current assets $ 2,569 $ 2,277 Other assets: Deposit $ 1,158 $ 1,158 Right of use asset under operating lease 179 183 Total other assets $ 1,337 $ 1,341 Accrued liabilities and other: Accrued payables $ 2,890 $ 3,005 Accrued capital expenditures 593 167 Accrued incentive and other compensation 611 941 Accrued royalties payable 1,046 977 Accrued taxes other than federal and state income tax 980 739 Accrued severance — 81 Operating lease liability 97 59 Asset retirement obligations due within one year 41 55 Accrued - other 36 3 Total accrued liabilities and other $ 6,294 $ 6,027 Note 13. Subsequent Events Dividend Declaration On February 5, 2024, the Company declared a quarterly cash dividend of $0.120 per share of common stock to shareholders of record on March 15, 2024 and payable on March 28, 2024. Derivatives On January 30, 2024, the Company entered into new derivative contracts covering 40,775 barrels of its crude oil comprised of put positions at $75.00 per barrel and fixed-price swap positions at $73.41 per barrel over the effective period of February 2024 through June 2024. SCOOP/STACK Acquisitions On January 5, 2024, the Company entered into separate Purchase and Sale Agreements (“PSAs”) with Red Sky Resources III, LLC, Red Sky Resources IV, LLC, and Coriolis Energy Partners I, LLC. Pursuant to the PSAs, the Company will acquire non-operating working interests in oil and natural gas properties in the SCOOP and STACK plays in central Oklahoma for a combined purchase price of approximately $43.5 million in cash. Contemporaneous with the execution of the PSAs, the Company paid deposits totaling $3.26 million. The Company expects to fund the balance of the consideration to be paid in the transactions with a combination of cash on hand and borrowings under its senior secured credit facility. 21 EVOLUTION PETROLEUM CORPORATION NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The acquired assets consist of an average working interest of approximately 3% net to Evolution, in 231 producing wells and as of the effective date, 21 gross drilled and uncompleted wells to be funded through completion by the sellers, in the SCOOP and STACK plays of the Anadarko Basin in Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, and Stephens counties, Oklahoma. The effective date of these acquisitions is November 1, 2023 and each transaction is expected to close in mid-February during the third quarter of fiscal 2024. The PSAs governing each transaction contain customary representations and warranties, covenants, indemnification, closing conditions and termination provisions and also provide for various purchase price adjustments, including adjusting the purchase price for the net cash flows of the properties between the effective date and closing date of the acquisition, to be calculated as of the closing date. 22 Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations Commonly Used Terms “Current “Year-ago Executive Overview General Evolution Petroleum Corporation is an independent energy company focused on maximizing total returns to its shareholders through the Our oil and natural gas properties consist of non-operated interests in the following areas: the Jonah Field in Sublette County, Wyoming; the Williston Basin in North Dakota; the Barnett Shale located in North Texas; the Hamilton Dome Field located in Hot Springs County, Wyoming; the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana; the Chaveroo oilfield in Chaves and Roosevelt Counties of New Mexico; as well as small overriding royalty interests in four onshore central Texas wells. Our non-operated interests in the Jonah Field, a natural gas and NGL producing field in Sublette County, Wyoming, consist of approximately 20% average net working interest and approximately 15% average net revenue interest located on approximately 950 net acres. The properties are operated by Jonah Energy, an Our non-operated interests in the Williston Basin, an oil and natural gas producing property, consist of Our non-operated interests in the Barnett Shale, a natural gas and 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 23 remaining working interest in the Our non-operated interests in the Delhi Our non-operated interests in the Chaveroo oilfield consist of a 50% net working interest, with an associated 41% revenue interest, in approximately 1,625 gross undeveloped acres associated with nine initial development locations with the right to acquire the same working interest in additional development locations and associated acreage at a fixed price. The field is operated by PEDEVCO Corp. (“PEDEVCO”). See “Chaveroo Oilfield Participation Agreement” below for further information. Recent Developments SCOOP/STACK Acquisitions The acquired assets consist of an average working interest of approximately 3% net to us, in 231 producing wells and as of the effective date, 21 gross drilled and uncompleted wells to be funded through completion by the sellers, in the SCOOP and STACK plays of the Anadarko Basin in Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, and Stephens counties, Oklahoma. The acquisitions also include approximately 3,700 net acres with more than 300 associated potential drilling opportunities. The effective date of these acquisitions is November 1, 2023 and each transaction is expected to close in mid-February during the third quarter of fiscal 2024. The PSAs governing each transaction contain customary representations and warranties, covenants, indemnification, closing conditions and termination provisions and also provide for various purchase price adjustments, including adjusting the purchase price for the net cash flows of the properties between the effective date and closing date of the acquisition, to be calculated as of the closing date. Appointment of Chief Accounting Officer On December 18, 2023, we announced that the Board of Directors approved the appointment of Kelly M. Beatty as Chief Accounting Officer, effective January 1, 2024. Ms. Beatty has been serving as Principal Accounting Officer since December 2022 and has served as the Company’s Controller since February 2022. Share Repurchase Program In November 2023, we entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan is effective until June 30, 2024, unless extended, renewed or terminated, and has a maximum authorized amount of $0.8 million over that period. We may alter the terms of the plan from time to time to the extent we determine changes are necessary to achieve the intended objectives of our repurchase program. No shares were repurchased under this program during the period ended December 31, 2023. 24 Chaveroo Oilfield Participation Agreement Pursuant to the Participation Agreement, we have the right, but not the obligation, to elect to participate in drilling locations on approximately 16,000 gross leasehold acres consisting of all leasehold rights from surface to the base of the San Andres formation, where PEDEVCO currently holds leasehold interest. We have agreed to pay PEDEVCO $450 per acre to acquire a 50% working interest share in the leases associated with the locations that we choose to participate in. We have entered into a standard operating agreement with PEDEVCO serving as the operator with respect to the development of the properties. The Participation Agreement includes customary representations and warranties of the parties and other terms and conditions that are standard in such participation agreements. During the three months ended September 30, 2023, we paid total cash consideration of $0.4 million, which includes less than $0.1 million of capitalized transaction costs, in exchange for a 50% working interest share in 1,625 gross undeveloped leasehold acres associated with two initial development blocks, comprised of nine development well locations. Following the completion of the initial nine development wells, we will have the right, but not the obligation, to elect to participate in the next development block. The Participation Agreement initially includes up to 80 gross drilling locations across twelve development blocks. Refer to Capital Expenditures below for a further discussion of Chaveroo drilling and completion activities since entering into the Participation Agreement. Risks and uncertainties The global economy was deeply impacted by the effects of the novel coronavirus (“COVID-19”) pandemic and related efforts to mitigate the spread of the disease. These events led to crude oil In addition, the conflict in the At times, we do maintain cash balances in excess of the 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 25 Liquidity and Capital Resources As of December 31, 2023 and June 30, 2023, we had no borrowings outstanding on our Senior Secured Credit Facility. As of December 31, 2023, we had $8.5 million in The Senior Secured Credit Facility has a maximum capacity of $50.0 million subject to a borrowing base determined by the Borrowings bear interest, at our option, at either the On May 5, 2023, we entered into the Tenth Amendment to the Senior Secured Credit Facility. This amendment, among other things, extended the maturity of our Senior Secured Credit Facility to April 9, 2026, converted our benchmark interest rate from LIBOR to SOFR plus a credit spread adjustment of 0.05%, and modified the Margined Collateral Value, as defined in the We have historically funded We Our 26 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 In November 2023, we entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in During the six months ended December 31, Based on discussions with our operators, we expect capital workover projects to continue in all the fields. Overall, for fiscal year 2024, we expect budgeted capital expenditures to be Funding for our anticipated capital expenditures Full Cost Pool Ceiling Test Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated 27 Overview of Cash Flow Activities Six Months Ended December 31, 2023 2022 Change Cash flows provided by operating activities $ 11,378 $ 27,769 $ (16,391) Cash flows used in investing activities (5,705) (2,917) (2,788) Cash flows used in financing activities (8,247) (29,422) 21,175 Net increase in cash and cash equivalents $ (2,574) $ (4,570) $ 1,996 Cash provided by operating activities for the six months ended December 31, 2023 decreased $16.4 million compared to the six months ended December 31, 2022 primarily due to a decrease in revenues. Total revenues decreased $31.8 million as compared to the prior year period primarily due to lower commodity prices coupled with lower sales volumes. Our Cash used in investing activities for the six months ended December 31, 2023 increased $2.8 million Net cash flows used in financing activities for the six months ended December 31, 2023 decreased $21.2 million from the six months ended December 31, 2022. In the prior year period, we had repayments totaling $21.3 million of 28 Results of Three Months Ended December 31, We reported net income of $1.1 million and $10.4 million for the three months ended December 31, 2023 and 2022, respectively. The following table Three Months Ended December 31, (in thousands, except per unit and per BOE amounts) 2023 2022 Variance Variance % Net income (loss) $ 1,082 $ 10,387 $ (9,305) (89.6) % Revenues: Crude oil 11,759 13,100 (1,341) (10.2) % Natural gas 6,531 17,370 (10,839) (62.4) % Natural gas liquids 2,734 3,206 (472) (14.7) % Total revenues 21,024 33,676 (12,652) (37.6) % Operating costs: Lease operating costs: CO2 costs 1,628 2,007 (379) (18.9) % Ad valorem and production taxes 1,272 2,096 (824) (39.3) % Other lease operating costs 9,458 10,938 (1,480) (13.5) % Depletion, depreciation, and accretion: Depletion of full cost proved oil and natural gas properties 4,238 3,178 1,060 33.4 % Accretion of asset retirement obligations 360 280 80 28.6 % General and administrative expenses: General and administrative 1,938 2,087 (149) (7.1) % Stock-based compensation 564 494 70 14.2 % Other income (expense): Net gain (loss) on derivative contracts — 846 (846) (100.0) % Interest and other income 104 7 97 1,385.7 % Interest expense (34) (129) 95 (73.6) % Income tax (expense) benefit (554) (2,933) 2,379 (81.1) % Production: Crude oil (MBBL) 159 166 (7) (4.2) % Natural gas (MMCF) 1,951 2,367 (416) (17.6) % Natural gas liquids (MBBL) 96 106 (10) (9.4) % Equivalent (MBOE)(1) 580 667 (87) (13.0) % Average daily production (BOEPD)(1) 6,304 7,250 (946) (13.0) % Average price per unit(2): Crude oil (BBL) $ 73.96 $ 78.92 $ (4.96) (6.3) % Natural gas (MCF) 3.35 7.34 (3.99) (54.4) % Natural Gas Liquids (BBL) 28.48 30.25 (1.77) (5.9) % Equivalent (BOE)(1) 36.25 50.49 (14.24) (28.2) % Average cost per unit: Operating costs: Lease operating costs: CO2 costs $ 2.81 $ 3.01 (0.20) (6.6) % Ad valorem and production taxes 2.19 3.14 (0.95) (30.3) % Other lease operating costs 16.31 16.40 (0.09) (0.5) % Depletion of full cost proved oil and natural gas properties 7.31 4.76 2.55 53.6 % General and administrative expenses: General and administrative 3.34 3.13 0.21 6.7 % Stock-based compensation 0.97 0.74 0.23 31.1 % 29 Revenues Crude oil, natural gas and NGL revenues were $21.0 million and $33.7 million for the three months ended December 31, 2023 and 2022, respectively. The decrease in revenues is primarily due to the decrease in our average realized price per BOE coupled with Lease Operating Costs Ad valorem and production taxes were $1.3 million and $2.1 million for the three months ended December 31, 2023 and 2022, respectively. On a per unit basis, ad valorem and production taxes were $2.19 per BOE and $3.14 per BOE for the three months ended December 31, 2023 and 2022, respectively. The decrease in ad valorem and production taxes is primarily due to decreases in oil and natural gas The following table summarizes CO2 costs per Mcf and CO2 volumes for the three months ended December 31, 2023 and 2022. CO2 purchase costs are for the Delhi Field. Under our contract with the Delhi Field operator, purchased CO2 is priced at 1% of the realized oil price in the field per MCF, plus sales taxes and transportation costs as per contract terms. Three Months Ended December 31, 2023 2022 Variance Variance % CO2 costs per MCF $ 0.97 $ 1.01 $ (0.04) (4.0) % CO2 volumes (MMCF per day, gross) 76.4 90.7 (14.3) (15.8) % The $0.4 million decrease in CO2 costs for the three months ended December 31, 2023 was primarily due to a 15.8% decrease in purchased CO2 volumes combined with a 4.0% decrease in CO2 costs per MCF, which was driven by a decrease in our average realized oil price. CO2 volumes injected were reduced compared to prior year period due to a reduction in CO2 purchase nominations. In the prior year period, CO2 purchase nominations were higher to compensate for reduced reservoir pressure. CO2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. We do not have any ownership in the CO2pipeline which is owned and operated by Denbury. On a per unit basis, CO2 costs were $2.81 per BOE and $3.01 per BOE for the three months ended December 31, 2023 and 2022, respectively. Other lease operating costs decreased $1.5 million, or 13.5%, compared to the prior year period primarily due to lower production combined with the lower commodity price environment. On a per unit basis, other lease operating costs decreased to $16.31 per BOE for the three months ended December 31, 2023 from $16.40 per BOE in the year-ago quarter. The largest decrease in operating costs is at our Barnett Shale properties and the Delhi Field. At the Barnett Shale, significant cost savings efforts are being prioritized due to the lower realized natural gas prices and the shut-in of certain low margin wells at current natural gas prices. We are incurring lower operating costs in all cost categories, especially lower water hauling costs and lower gathering, transportation and processing charges. At Delhi Field, we have seen lower electricity charges due to lower commodity prices. 30 Depletion of Full Cost Proved Oil and Depletion expense increased $1.1 million or 33.4% from $3.2 million to $4.2 million for the three months ended December 31, 2023 primarily due to an increase in the depletion rate. On a per unit basis, depletion expense was $7.31 per BOE and $4.76 per BOE for the three months ended December 31, 2023 and 2022, respectively. The depletion rate of General and Administrative Expenses General and administrative expenses for the three months ended December 31, 2023 decreased $0.1 million, or 7.1%, to $1.9 million compared to $2.1 million for the prior year period. The decrease primarily relates to lower consulting fees totaling approximately $0.1 million related to our search for a CEO in the prior year period. On a per unit basis, general and administrative expenses were $3.34 per BOE and $3.13 per BOE for the three months ended December 31, 2023 and 2022, respectively. The slight increase on a per unit basis is primarily the result of the decrease in production for the current year period. Stock-based Compensation Expense Stock-based compensation expense for the three months ended December 31, 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 Three Months Ended December 31, (in thousands, except per unit and per BOE amounts) 2023 2022 Variance Variance % Realized gain (loss) on derivative contracts $ — $ (224) $ 224 (100.0) % Unrealized gain (loss) on derivative contracts — 1,070 (1,070) (100.0) % Total net gain (loss) on derivative contracts $ — $ 846 $ (846) (100.0) % Average realized crude oil price per BBL $ 73.96 $ 78.92 $ (4.96) (6.3) % Cash effect of oil derivative contracts per BBL — — — — % Crude oil price per BBL (including impact of realized derivatives) $ 73.96 $ 78.92 $ (4.96) (6.3) % Average realized natural gas price per MCF $ 3.35 $ 7.34 $ (3.99) (54.4) % Cash effect of natural gas derivative contracts per MCF — (0.09) 0.09 (100) % Natural gas price per MCF (including impact of realized derivatives) $ 3.35 $ 7.25 $ (3.90) (53.8) % 31 Interest Expense Interest expense decreased $0.1 million for the three months ended December 31, Income Tax (Expense) Benefit For the three months ended December 31, 2023, we recognized income tax expense of $0.6 million on net income before income taxes of 32 We reported net income of $2.6 million and $21.1 million for the six months ended December 31, 2023 and 2022, respectively. The following table Six Months Ended December 31, (in thousands, except per unit and per BOE amounts) 2023 2022 Variance Variance % Net income (loss) $ 2,556 $ 21,094 $ (18,538) (87.9) % Revenues: Crude oil 24,375 28,263 (3,888) (13.8) % Natural gas 12,083 37,218 (25,135) (67.5) % Natural gas liquids 5,167 7,992 (2,825) (35.3) % Total revenues 41,625 73,473 (31,848) (43.3) % Operating costs: Lease operating costs: CO2 costs 3,206 4,206 (1,000) (23.8) % Ad valorem and production taxes 2,550 5,359 (2,809) (52.4) % Other lease operating costs 18,485 24,592 (6,107) (24.8) % Depletion, depreciation, and accretion: Depletion of full cost proved oil and natural gas properties 8,148 6,500 1,648 25.4 % Accretion of asset retirement obligations 712 556 156 28.1 % General and administrative expenses: General and administrative 4,069 4,351 (282) (6.5) % Stock-based compensation 1,036 702 334 47.6 % Other income (expense): Net gain (loss) on derivative contracts — 243 (243) (100.0) % Interest and other income 220 13 207 1,592.3 % Interest expense (66) (372) 306 (82.3) % Income tax (expense) benefit (1,017) (5,997) 4,980 (83.0) % Production: Crude oil (MBBL) 320 334 (14) (4.2) % Natural gas (MMCF) 3,976 4,861 (885) (18.2) % Natural gas liquids (MBBL) 191 221 (30) (13.6) % Equivalent (MBOE)(1) 1,174 1,365 (191) (14.0) % Average daily production (BOEPD)(1) 6,380 7,418 (1,038) (14.0) % Average price per unit(2): Crude oil (BBL) $ 76.17 $ 84.62 $ (8.45) (10.0) % Natural gas (MCF) 3.04 7.66 (4.62) (60.3) % Natural Gas Liquids (BBL) 27.05 36.16 (9.11) (25.2) % Equivalent (BOE)(1) 35.46 53.83 (18.37) (34.1) % Average cost per unit: Operating costs: Lease operating costs: CO2 costs $ 2.73 $ 3.08 (0.35) (11.4) % Ad valorem and production taxes 2.17 3.93 (1.76) (44.8) % Other lease operating costs 15.75 18.02 (2.27) (12.6) % Depletion of full cost proved oil and natural gas properties 6.94 4.76 2.18 45.8 % General and administrative expenses: General and administrative 3.47 3.19 0.28 8.8 % Stock-based compensation 0.88 0.51 0.37 72.5 % 33 Revenues Crude oil, natural gas and NGL revenues were $41.6 million and $73.5 million for the six months ended December 31, 2023 and 2022, respectively. The decrease in revenues is primarily due to the decrease in our average realized price per BOE coupled with Lease Operating Costs Ad valorem and production taxes were $2.6 million and $5.4 million for the six months ended December 31, 2023 and 2022, respectively. On a per unit basis, ad valorem and production taxes were $2.17 per BOE and $3.93 per BOE for the six months ended December 31, 2023 and 2022, respectively. The decrease in ad valorem and production taxes is primarily due to decreases in oil and natural gas The following table summarizes CO2 costs per Mcf and CO2 volumes for the six months ended December 31, 2023 and 2022. CO2 purchase costs are for the Delhi Field. Under our contract with the Delhi Field operator, purchased CO2 is priced at 1% of the realized oil price in the field per MCF, plus sales taxes and transportation costs as per contract terms. Six Months Ended December 31, 2023 2022 Variance Variance % CO2 costs per MCF $ 0.98 $ 1.06 $ (0.08) (7.5) % CO2 volumes (MMCF per day, gross) 74.4 90.4 (16.0) (17.7) % The $1.0 million decrease in CO2 costs for the six months ended December 31, 2023 was primarily due to a 17.7% decrease in purchased CO2 volumes combined with a 7.5% decrease in CO2 costs per MCF, which was driven by a decrease in our average realized oil price. CO2 volumes injected were reduced compared to prior year period due to a reduction in CO2 purchase nominations and higher ambient temperatures in the Delhi Field during the current period. In the prior year period, CO2 purchase nominations were higher to compensate for reduced reservoir pressure. CO2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. We do not have any ownership in the CO2 pipeline which is owned and operated by Denbury. On a per unit basis, CO2 costs were $2.73 per BOE and $3.08 per BOE for the six months ended December 31, 2023 and 2022, respectively. Other lease operating costs decreased $6.1 million, or 24.8%, compared to the prior year period primarily due to lower production combined with the lower commodity price environment. On a per unit basis, other lease operating costs decreased to $15.75 per BOE for the six months ended December 31, 2023 from $18.02 per BOE in the year-ago quarter. The largest decrease in operating costs is at our Barnett Shale properties and the Delhi Field. At the Barnett Shale, significant cost savings efforts are being prioritized due to the lower realized natural gas prices and the shut-in of certain low margin wells at current natural gas prices. We are incurring lower operating costs in all cost categories, especially lower water hauling costs and lower gathering, transportation and processing charges. At Delhi Field, we have seen lower electricity charges due to lower commodity prices. 34 Depletion of Full Cost Proved Oil and Depletion expense increased $1.6 million or 25.4% from $6.5 million to $8.1 million for the six months ended December 31, 2023 primarily due to an increase in the depletion rate. On a per unit basis, depletion expense was $6.94 per BOE and $4.76 per BOE for the six months ended December 31, 2023 and 2022, respectively. The depletion rate of General and Administrative Expenses General and administrative expenses for the six months ended December 31, 2023 decreased $0.3 million, or 6.5%, to $4.1 million compared to $4.4 million for the prior year period. The decrease primarily relates to lower consulting fees totaling approximately $0.3 million related to our search for a CEO and outsourced services in the prior year period. On a per unit basis, general and administrative expenses were $3.47 per BOE and $3.19 per BOE for the six months ended December 31, 2023 and 2022, respectively. The slight increase on a per unit basis is primarily the result of the decrease in production for the current year period. Stock-based Compensation Expense Stock-based compensation expense for the six months ended December 31, 35 Net Periodically, we utilize commodity derivative financial instruments to Six Months Ended December 31, (in thousands, except per unit and per BOE amounts) 2023 2022 Variance Variance % Realized gain (loss) on derivative contracts $ — $ (1,946) $ 1,946 (100.0) % Unrealized gain (loss) on derivative contracts — 2,189 (2,189) (100.0) % Total net gain (loss) on derivative contracts $ — $ 243 $ (243) (100.0) % Average realized crude oil price per BBL $ 76.17 $ 84.62 $ (8.45) (10.0) % Cash effect of oil derivative contracts per BBL — (0.73) 0.73 (100.0) % Crude oil price per BBL (including impact of realized derivatives) $ 76.17 $ 83.89 $ (7.72) (9.2) % Average realized natural gas price per MCF $ 3.04 $ 7.66 $ (4.62) (60.3) % Cash effect of natural gas derivative contracts per MCF — (0.35) 0.35 (100) % Natural gas price per MCF (including impact of realized derivatives) $ 3.04 $ 7.31 $ (4.27) (58.4) % Interest Expense Interest expense decreased $0.3 million for the six months ended December 31, Income Tax (Expense) Benefit For the six months ended December 31, 2023, we recognized income tax expense of 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 36 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 Item 3. Derivative Instruments and Hedging Activity We are exposed to various risks, We are exposed to Interest Rate Risk We Item 4. 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 As required by Under the supervision and with the participation of 37 Item 1. See Note 9, “Commitments and Contingencies” to our unaudited condensed consolidated financial statements in Item 1A. Our Annual Report on Form 10-K for the year ended June 30, 38 Item 2. Issuer Purchases of Equity Securities The table below summarizes information about the Company's purchases of its equity securities during the (c) Total number (d) Maximum dollar value (a) Total number of shares of shares that may yet be of shares purchased as part purchased under the purchased and (b) Average price of public announced plans or programs Period received (1) paid per share (1) plans or programs(2) (in thousands)(2) October 2023 — $ — — $ 21,152 November 2023 17,436 6.20 — 21,152 December 2023 — — — 21,152 Item 3. Defaults Upon Senior Securities Item 5. None. 39 Item 6. 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 3.3 31.1** 31.2** 32.1** 32.2** 101.INS* Inline XBRL Instance Document 101.SCH* Inline XBRL Taxonomy Extension Schema Document 101.CAL* Inline XBRL Taxonomy Extension Calculation Linkbase Document 101.DEF* Inline XBRL Taxonomy Extension Definition Linkbase Document 101.LAB* Inline XBRL Taxonomy Extension Label Linkbase Document 101.PRE* Inline XBRL Taxonomy Extension Presentation Linkbase Document 104* Cover Page Interactive Data File (embedded within the Inline XBRL document) * Attached hereto. ** Furnished herewith. 40 Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. Evolution Petroleum Corporation Date: February 7, 2024 By: /s/ KELLY W. LOYD Kelly W. Loyd President and Chief Executive Officer (Principal Executive Officer) and Director By: /s/ RYAN STASH Ryan Stash Senior Vice President and Chief Financial Officer (Principal Financial Officer) and Treasurer 41CORPORATIONNevada41-1781991
incorporation or organization)(713) Not Applicable(Former name, former address and former fiscal year if changed since last report)ý☒ No: oand 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: odefinitionsdefinition 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.oxNon-accelerated filer o (Do not check if a smaller reporting company) Smaller reporting company ooIf 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. oo☐ No: ýThe number of☒ outstanding of the registrant’s common stock,Registrant’s Common Stock, $0.001 par value $0.001, asper share, were outstanding. AND SUBSIDIARIESPage2. PART I — FINANCIAL INFORMATIONITEM 1. CONSOLIDATEDCONDENSEDFINANCIAL STATEMENTSSubsidiariesunless the context otherwise requires, its wholly-owned subsidiaries.Consolidated Condensed Balance Sheets(Unaudited) December 31,
2017 June 30,
2017Assets Current assets Cash and cash equivalents $ 25,743,497 $ 23,028,153 Receivables 4,078,153 2,726,702 Prepaid expenses and other current assets 824,048 387,672 Total current assets 30,645,698 26,142,527 Oil and natural gas property and equipment, net (full-cost method of accounting) 60,093,807 61,790,068 Other property and equipment, net 32,265 40,689 Total property and equipment 60,126,072 61,830,757 Other assets 260,468 295,384 Total assets $ 91,032,238 $ 88,268,668 Liabilities and Stockholders’ Equity Current liabilities Accounts payable $ 2,400,202 $ 1,994,255 Accrued liabilities and other 660,467 724,639 Total current liabilities 3,060,669 2,718,894 Long term liabilities Deferred income taxes 10,580,381 15,826,291 Asset retirement obligations 1,297,028 1,253,628 Total liabilities 14,938,078 19,798,813 Commitments and contingencies (Note 14) Stockholders’ equity Common stock; par value $0.001; 100,000,000 shares authorized; 33,171,514 and 33,087,308 shares issued and outstanding as of December 31, 2017 and June 30, 2017, respectively 33,171 33,087 Additional paid-in capital 41,538,133 40,961,957 Retained earnings 34,522,856 27,474,811 Total stockholders’ equity 76,094,160 68,469,855 Total liabilities and stockholders’ equity $ 91,032,238 $ 88,268,668 ● our expectations of plans, strategies and objectives, including anticipated development activity and capital spending; ● our capital allocation strategy, capital structure, anticipated sources of funding, growth in long-term shareholder value and ability to preserve balance sheet strength; ● the benefits of our multi-basin portfolio, including operational and commodity flexibility; ● our ability to maximize cash flow and the application of excess cash flows to pay dividends and repurchase shares pursuant to our share repurchase program; ● estimates of our oil, natural gas and natural gas liquids (“NGLs”) production and commodity mix; ● anticipated oil, natural gas and NGL prices; ● anticipated drilling and completions activity; ● estimates of our oil, natural gas and NGL reserves and recoverable quantities; ● our ability to access credit facilities and other sources of liquidity to meet financial obligations throughout commodity price cycles; ● limitations on our ability to obtain funding based on environmental, social, and corporate governance (“ESG”) performance; ● future interest expense; ● our ability to manage debt and financial ratios, finance growth and comply with financial covenants; ● the implementation and outcomes of risk management programs, including exposure to commodity price and interest rate fluctuations, the volume of oil and natural gas production hedged, and the markets or physical sales locations hedged; ● the impact of changes in federal, state, provincial and local, rules and regulations; ● anticipated compliance with current or proposed environmental requirements, including the costs thereof; ● the possible impact of greenhouse gas (“GHG”) emissions limitations and renewable energy incentives; ● adequacy of provisions for abandonment and site reclamation costs; ● our operational and financial flexibility, discipline and ability to respond to evolving market conditions; ● the declaration and payment of future dividends and any anticipated repurchase of our outstanding common shares; ● the adequacy of our provision for taxes and legal claims; ● our ability to manage cost inflation and expected cost structures, including expected operating, transportation, processing and labor expenses; ● our competitiveness relative to our peers, including with respect to capital, materials, people, assets and production; ● oil, natural gas and NGL inventories and global demand for oil, natural gas and NGLs; ● the outlook of the oil and natural gas industry generally, including impacts from changes to the geopolitical environment; ● adverse weather events; ● anticipated staffing levels; ● anticipated payments related to our commitments, obligations and contingencies, and the ability to satisfy the same; and ● the possible impact of accounting and tax pronouncements, rule changes and standards. ● 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. condensed financial statements.Evolution Petroleum Corporation and SubsidiariesConsolidated Condensed Statements of Operations(Unaudited) Three Months Ended
December 31, Six Months Ended
December 31, 2017 2016 2017 2016 Revenues Crude oil $ 10,185,635 $ 8,529,817 $ 18,014,890 $ 16,123,672 Natural gas liquids 881,276 — 1,589,892 89 Natural gas — — — (4 ) Total revenues 11,066,911 8,529,817 19,604,782 16,123,757 Operating costs Production costs 2,914,512 2,292,421 5,806,098 4,637,062 Depreciation, depletion and amortization 1,633,868 1,307,510 3,152,411 2,580,949 Accretion of discount on asset retirement obligations 23,023 13,106 44,602 26,330 General and administrative expenses * 1,666,256 1,241,399 3,235,960 2,476,442 Total operating costs 6,237,659 4,854,436 12,239,071 9,720,783 Income from operations 4,829,252 3,675,381 7,365,711 6,402,974 Other Gain on realized derivative instruments, net — — — 90 Loss on unrealized derivative instruments, net — — — (14,132 ) Interest and other income 15,841 14,061 30,691 26,806 Interest expense (20,456 ) (20,711 ) (40,911 ) (41,056 ) Income before income taxes 4,824,637 3,668,731 7,355,491 6,374,682 Income tax provision (benefit) (5,052,211 ) 1,361,097 (4,661,889 ) 2,250,273 Net income attributable to the Company 9,876,848 2,307,634 12,017,380 4,124,409 Dividends on preferred stock — — — 250,990 Deemed dividend on redeemed preferred shares — — — 1,002,440 Net income available to common stockholders $ 9,876,848 $ 2,307,634 $ 12,017,380 $ 2,870,979 Earnings per common share Basic $ 0.30 $ 0.07 $ 0.36 $ 0.09 Diluted $ 0.30 $ 0.07 $ 0.36 $ 0.09 Weighted average number of common shares Basic 33,109,448 33,047,166 33,099,546 33,002,088 Diluted 33,140,278 33,083,027 33,140,257 33,037,269 * General and administrative expenses for the three months ended December 31, 2017 and 2016 included non-cash stock-based compensation expense of $484,326 and $275,184, respectively. For the corresponding six month periods, non-cash stock-based compensation expense was $971,810 and $586,872, respectively.Evolution Petroleum Corporation and SubsidiariesConsolidated Condensed Statements of Cash Flows Six Months Ended
December 31, 2017 2016 Cash flows from operating activities Net income attributable to the Company $ 12,017,380 $ 4,124,409 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 3,180,545 2,609,356 Stock-based compensation 971,810 586,872 Accretion of discount on asset retirement obligations 44,602 26,330 Settlements of asset retirement obligations — (121,391 ) Deferred income taxes (benefit) (5,245,910 ) 1,709,519 Loss on derivative instruments, net — 14,042 Changes in operating assets and liabilities: Receivables (1,351,451 ) (462,981 ) Prepaid expenses and other current assets (436,376 ) (367,039 ) Accounts payable and accrued expenses (83,013 ) (1,955,546 ) Income taxes payable — (311,306 ) Net cash provided by operating activities 9,097,587 5,852,265 Cash flows from investing activities Derivative settlement payments paid — (318,618 ) Capital expenditures for oil and natural gas properties (1,017,358 ) (7,978,130 ) Capital expenditures for other property and equipment — (30,447 ) Net cash used in investing activities (1,017,358 ) (8,327,195 ) Cash flows from financing activities Cash dividends to preferred stockholders — (250,990 ) Cash dividends to common stockholders (4,969,335 ) (3,801,962 ) Common share repurchases, including shares surrendered for tax withholding (395,550 ) (459,858 ) Redemption of preferred shares — (7,932,975 ) Other — 32 Net cash used in financing activities (5,364,885 ) (12,445,753 ) Net increase (decrease) in cash and cash equivalents 2,715,344 (14,920,683 ) Cash and cash equivalents, beginning of period 23,028,153 34,077,060 Cash and cash equivalents, end of period $ 25,743,497 $ 19,156,377 Supplemental disclosures of cash flow information: Six Months Ended
December 31, 2017 2016 Income taxes paid $ 1,136,754 $ 1,278,773 Non-cash transactions: Change in accounts payable used to acquire property and equipment 424,365 (1,516,932 ) Oil and natural gas property costs incurred through recognition of asset retirement obligations (779 ) — condensed financial statements.Evolution Petroleum Corporation and SubsidiariesConsolidated Condensed Statement of Changes in Stockholders' EquityFor the Six Months Ended December 31, 2017(Unaudited) 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 condensed financial statements.5And SubsidiariesNotes to Unaudited Consolidated Condensed Financial StatementsNote 1—Organization(“Evolution,” and Basis of PreparationNature 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 under the laws of the State of Nevada. We are engaged primarilynatural gas properties in the development and productionUnited States. The Company’s long-term goal is to maximize total shareholder return from a diversified portfolio of long-life oil and natural gas reserves. 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. 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 12, “Additional Financial Statement Information.” This reclassification has no impact on the previously reported unaudited condensed consolidated balance sheets, net income or stockholders'stockholders’ equity.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.Pronouncements.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.JanuaryJune 2016, the FASB issued ASU 2016-01,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.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. 6Evolution Petroleum Corporation And SubsidiariesNotesUnaudited Consolidated Condensed Financial StatementsIn 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.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 receives payment from the sale of cash flows.oil and natural gas production one to two months after delivery.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.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.a material effectbeen 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 itsthe unaudited condensed consolidated statementsbalance sheets.20172023, $3.4 million of oil and June 30, 2017, our receivables consistednatural gas property costs were not subject to amortization. On September 12, 2023, the Company entered into a Participation Agreement with PEDEVCO for the joint development of a portion of PEDEVCO’s Permian Basin property in the Chaveroo Field, located in Chaves and Roosevelt Counties, New Mexico. The Participation Agreement does not include any of PEDEVCO’s existing vertical or horizontal wells.following: December 31,
2017 June 30,
2017Receivables 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 Expensesinitial nine development wells, the Company will have the right, but not the obligation, to elect to participate and Other Current Assets20172023, the Company has incurred approximately $3.0 million in capital expenditures related to the drilling and June 30, 2017, our prepaid expensescompletion of an initial three wells. These capital expenditures are recorded as unevaluated property costs.other current assets consistednatural gas properties. All costs of acquisition, exploration, and development of oil and natural gas reserves are capitalized as the following: December 31,
2017 June 30,
2017Prepaid insurance $ 86,904 $ 169,416 Retainers and deposits 7,589 7,553 Prepaid federal and state income taxes 674,028 121,232 Other prepaid expenses 55,527 89,471 Prepaid expenses and other current assets $ 824,048 $ 387,672 7Evolution Petroleum Corporation And SubsidiariesNotes to Unaudited Consolidated Condensed Financial StatementsNote 4 —Property and EquipmentAs of December 31, 2017 and June 30, 2017, our oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and othernatural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs would be charged to expense as a write-down of oil and natural gas properties.equipment consistedall or a portion of the following: December 31,
2017 June 30,
2017Oil 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 20172023 and 2022, the Company incurred development capital expenditures of $2.4 million and $2.1 million, respectively.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 million$50.0 million. On May 5, 2023, the Company entered into the Tenth Amendment to the Senior Secured Credit Facility extending the maturity to April 9, 2026. The Tenth Amendment also replaced the London Interbank Offered Rate ("LIBOR") with the Secured Overnight Financing Rate (“SOFR”) plus a credit spread adjustment of 0.05% to effectively convert SOFR to a LIBOR equivalent and $6.5 million, respectively,modifies the Margined Collateral Value, as defined in the Delhi field.Note 5—Other Assets20172023, the Company did not have any borrowings outstanding under its Senior Secured Credit Facility, resulting in $50.0 million of available borrowing capacity. As of December 31, 2023, the Company is in compliance with the financial covenants under the Senior Secured Credit Facility.2017,2020 through June 30, 2023 for federal tax purposes and for the fiscal years ended June 30, 2019 through June 30, 2023 for state tax purposes. To the extent the Company utilizes net operating losses (“NOLs”) generated in earlier years, such earlier years may also be subject to audit.consistedand liabilities for financial reporting purposes and the amounts used for income tax purposes.following:Company’s derivative contracts had expired. The Company has no open derivative contracts as of December 31, 2023 or June 30, 2023, and the Company did not post collateral under any of its derivative contracts during the periods in which contracts were open as they were secured under the Company’s Senior Secured Credit Facility. December 31,
2017 June 30,
2017Royalty rights $ 108,512 $ 108,512 Less: Accumulated amortization of royalty rights (27,128 ) (20,346 ) Investment in Well Lift Inc., at cost 108,750 108,750 Deferred loan costs 168,972 168,972 Less: Accumulated amortization of deferred loan costs (98,638 ) (70,504 ) Other assets, net $ 260,468 $ 295,384 Our royalty rightsinvestmenta purchased put that establishes a minimum price. Fixed-price swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for the volumes under contract. The Company has elected not to designate its open derivative contracts for hedge accounting. Accordingly, the Company records the net change in Well Lift, Inc. ("WLI") resulted from the separation of our artificial lift technology operations in December 2015. We conveyed our patents and other intellectual property to WLI and retained a 5% royalty on future gross revenues associated the technology. We own 17.5%mark-to-market valuation of the common stockderivative contracts and all payments and receipts on settled derivative contracts in “Net gain (loss) on derivative contracts” on the unaudited condensed consolidated statements of WLI and account for our investment under the cost method. Any dividends paidoperations.as incomeat fair market value in accordance with ASC 815, Derivatives and any returnHedging (“ASC 815”) and ASC 820, Fair Value Measurement (“ASC 820”). The following table summarizes the location and amounts of capital reduces our cost basisthe Company’s realized and unrealized gains and losses on derivative contracts in the investment. Our investmentCompany’s unaudited condensed consolidated statements of operations for the six months ended December 31, 2023 and 2022 (in thousands). “Realized gain (loss) on derivative contracts” represents all receipts (payments) on derivative contracts settled during the period. “Unrealized gain (loss) on derivative contracts” represents the net change in WLIthe mark-to-market valuation of the derivative contracts.evaluateda standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for impairmentoffsetting of amounts payable or receivable between the Company and the counterparty, at least quarterlythe election of both parties, for transactions that occur on the same date and in the same currency.when management identifiesliabilities.eventsperiod presented in this report. The Company did not have any open positions at December 31, 2023 or changesJune 30, 2023.circumstances that mightaccordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have a significant adverse effectbeen determined at discrete points in time based on therelevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable, and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the investment. There is no publishedCompany’s Senior Secured Credit Facility approximates carrying value because the interest rates approximate current market valuerates.this private investment, so it is not practicable to value itnonfinancial assets and liabilities measured at fair market value on a periodicnon-recurring basis.8Evolution Petroleum Corporation And SubsidiariesNotes to Unaudited Consolidated Condensed Financial StatementsNote 6—Accrued Liabilities and OtherAs of December 31, 2017 and June 30, 2017, our other current liabilities consisted of the following: December 31,
2017 June 30,
2017Accrued incentive and other compensation $ 292,382 $ 413,113 Accrued severance payments 46,719 — Asset retirement obligations due within one year 35,539 35,115 Accrued royalties, including suspended accounts 11,524 17,708 Accrued franchise taxes 82,800 150,062 Accrued ad valorem taxes 191,503 108,641 Accrued liabilities and other $ 660,467 $ 724,639 Note 7—Asset Retirement ObligationsOur asset retirement obligations represent(“ARO”) for which fair value is calculated using discounted future cash flows derived from historical costs and management’s expectations of future cost environments. Significant Level 3 inputs used in the calculation of ARO include the costs of plugging and abandoning wells, surface restoration, and reserve lives. Subsequent to initial recognition, revisions to estimated asset retirement obligations are made when changes occur for input values. See Note 8, “Asset Retirement Obligations,” for a reconciliation of the beginning and ending balances of the liability for the Company’s ARO.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.beginning and ending asset retirement obligationsactivity related to the Company’s ARO liability (inclusive of the current portion) for the six monthsperiod ended December 31, 20172023 (in thousands):forContingenciesyear ended June 30, 2017: December 31,
2017 June 30,
2017Asset retirement obligations — beginning of period $ 1,288,743 $ 962,196 Liabilities incurred — 52,792 Liabilities settled — (157,164 ) Liabilities sold — (47,817 ) Accretion of discount 44,602 59,664 Revision of previous estimates (778 ) 419,072 Asset retirement obligations — end of period $ 1,332,567 $ 1,288,743 Less current portion in accrued liabilities (35,539 ) (35,115 ) Long-term portion of asset retirement obligations $ 1,297,028 $ 1,253,628 2017, we2023, the Company had 33,171,514 shares33,506,794 shares of common stock outstanding.WeAs of December 31, 2023, the Company has cumulatively paid over $110.4 million in cash dividends. The Company paid dividends of $4,969,335$8.0 million and $3,801,962$8.1 million to ourits common shareholdersstockholders during the six months ended December 31, 20172023 and 2016,2022, respectively. These dividend payments consisted of two quarterlyThe 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: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.time without prior notice.9Evolution Petroleum Corporation And SubsidiariesNotesUnaudited Consolidated Condensed Financial Statements20172023 and 2016,2022, 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 in thevesting.table: Six Months Ended
December 31, 2017 2016 Number of treasury shares acquired 55,018 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 RedemptionIn September 2016, the Company announced the decision to redeemtable summarizes all 317,319 outstanding shares of its 8.5% Series A Cumulative Preferred Stock. The redemption occurred in November 2016 at the stated value of $25.00 per share plus all accumulated and unpaid distributions, for an aggregate redemption cost of $7,932,975.On September 30, 2016, in connection with the planned redemption, the Company recorded a deemed dividend of $1,002,440, representing the difference between the redemption consideration paid and the historical net issuance proceeds of the preferred shares. Accordingly, net income was adjusted for this deemed dividend to determine net income attributable to common shareholders and earnings per common share.Dividends on the Series A Cumulative Preferred Stock were paid at a fixed rate of 8.5% per annum on the $25.00 per share liquidation preference, payable monthly. Duringtreasury stock purchases during the six months ended December 31, 2016, we paid cash dividends of $250,990 to holders of our Series A Preferred Stock prior to the November 2016 redemption date.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 December 31, 20172023 and are subject to change based on ourthe Company’s final tax calculations at the end of the fiscal year.Note 9 — At the December 8, 2016 annual meeting, the stockholders approved the adoption of the(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 December 31, 2017, 987,8452023 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 availablegrants undercompensation expense. During the 2004 Plan. All outstanding awards granted underthree and six months ended December 31, 2023, the 2004 Plan continueCompany recognized $0.6 million and $1.0 million, respectively, related to be subjectstock-based compensation. During the three and six months ended December 31, 2022, the Company recognized $0.5 million and $0.7 million, respectively, related to stock-based compensation expense. Stock-based compensation expense is recorded as a component of “General and administrative expenses” on the terms and conditions as set forth in the agreements evidencing such awards and the termsunaudited condensed consolidated statements of the 2004 Plan. Under these agreements, we have outstanding grants ofoperations. 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 StockThe 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 vesting10Evolution Petroleum Corporation And SubsidiariesNotes to Unaudited Consolidated Condensed Financial Statementsthresholds 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 directorsCertain 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.grants which vestAwards and Performance-Based Contingent Stock Unitsservicethe 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.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.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.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:the Company's total return compared to the historical volatilitiesContents the other companies in the index. Compensation expense for market-based awards is recognized over the expected vesting period using the straight-line method, so long as the holder remains an employee or director of the Company. Total compensation expense is based on the fair value of the awards at the date of grant and is independent of vesting or expiration of the awards, except for termination of service.Unvested Restricted Stock awards at December 31, 20172023 consisted of the following:Number of
Restricted
Shares Weighted
Average
Grant-Date
Fair ValueService-based awards 220,068 $ 6.68 Performance-based awards 50,360 5.67 Market-based awards 50,359 5.44 Unvested Restricted Stock at December 31, 2017 320,787 $ 6.33 Restricted Stockrestricted stock award transactions for the six months ended December 31, 2017: Number of
Restricted
Shares Weighted
Average
Grant-Date
Fair Value Unamortized Compensation Expense at December 31, 2017 Weighted Average Remaining Amortization Period (Years) Unvested at July 1, 2017 391,624 $ 6.22 Service-based shares granted 112,155 6.96 Vested (163,431 ) 6.52 Forfeited (19,561 ) 6.16 Unvested Restricted Stock at December 31, 2017 320,787 $ 6.33 $ 1,510,203 1.39 11Evolution Petroleum Corporation And SubsidiariesNotes to Unaudited Consolidated Condensed Financial StatementsUnvested Contingent Restricted Stock awards at December 31, 2017 consisted of the following:Number of
Contingent
Restricted
Shares Weighted
Average
Grant-Date
Fair ValuePerformance-based awards 36,688 $ 7.04 Market-based awards 25,180 3.42 Unvested contingent shares at December 31, 2017 61,868 $ 5.57 Contingent Restricted Stockcontingent restricted stock unit transactions for the six months ended December 31, 2017:2023: 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, 2017 113,270 $ 4.64 Vested (46,630 ) 3.34 Forfeited (4,772 ) 5.30 Unvested contingent shares at December 31, 2017 61,868 $ 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 10—DerivativesFrom 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.12Evolution Petroleum Corporation And SubsidiariesNotes to Unaudited Consolidated Condensed Financial StatementsFor 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.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.13Evolution Petroleum Corporation And SubsidiariesNotes to Unaudited Consolidated Condensed Financial StatementsNote 12 —Net Income Per11. Earnings (Loss) per Common Shareincomeearnings (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 — Basic 33,109,448 33,047,166 33,099,546 33,002,088 Effect of dilutive securities: Contingent restricted stock grants 30,830 9,836 40,711 10,909 Stock options — 26,025 — 24,272 Weighted average number of common shares and dilutive potential common shares used in diluted EPS 33,140,278 33,083,027 33,140,257 33,037,269 Net income per common share — Basic $ 0.30 $ 0.07 $ 0.36 $ 0.09 Net income per common share — Diluted $ 0.30 $ 0.07 $ 0.36 $ 0.09 Outstanding potentially dilutive securities ascommon share, reflecting the application of December 31, 2017 were as follows:Outstanding Potentially Dilutive SecuritiesWeightedAverageExercise PriceAt December 31, 2017Contingent Restricted Stock grants—61,868Outstanding potentially dilutive securities as of December 31, 2016 were as follows:Outstanding Potentially Dilutive Securities Weighted
Average
Exercise Price At December 31, 2016 Contingent Restricted Stock grants $ — 113,270 Stock Options 2.19 35,231 Total outstanding potentially dilutive securities $ 0.52 148,501 Note 13 — Senior Secured Credit AgreementOn April 11, 2016, the Company entered into a three-year, senior secured reserve-based credit facility ("Facility") in an amount up to $50 million. The Facility replaces the Company's previous unsecured credit facility which expired in April 2016. The borrowing base under the Facility has been set at $10two-class method (in thousands, except per share amounts):was subsequently increased to $400.1 million effective February 1, 2018. As of December 31, 2017, the Company was in compliance with all covenants contained in the Facility, and no amounts were outstanding under the Facility.Borrowings from the Facility may be used for the acquisition and development of oil and gas properties and for letters of credit and other general corporate purposes. Availability of borrowings under the Facility is subject to semi-annual borrowing base redeterminations.The Facility included a placement fee of 0.50% on the initial borrowing base, amounting to $50,000, and carries a commitment fee of 0.25% per annum on the undrawn portion of the borrowing base. Any borrowings under the Facility will bear interest, at the Company’s option, at either LIBOR plus 2.75% or the Prime Rate, as defined, plus 1.00%. The Facility contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (a) a maximum total leverage ratio of not more than 3.00 to 1.00, (b) a debt service coverage ratio of not less than 1.10 to 1.00, and (c) a consolidated tangible net worth of not less than $40 million, all as defined under the Facility.14Evolution Petroleum Corporation And SubsidiariesNotes to Unaudited Consolidated Condensed Financial StatementsIn connection with this agreement, the Company incurred $168,972 of debt issuance costs. Such costs were capitalized in Other Assets and are being amortized to expense. The unamortized balance in debt issuance costs related to the Facility was $70,334 as of December 31, 2017.Note 14 — Commitments and ContingenciesWe 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, 20172023, respectively, were not included in the computation of diluted earnings per common share because the effect would have been anti-dilutive.2016 was $39,049performance-based), totaling approximately 90,000 and $53,425, respectively.49,000 for the three and six months ended December 31, 2022, respectively, were not included in the computation of diluted earnings per common share because the effect would have been anti-dilutive.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 OverviewGeneralWe 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"quarter"quarter” refers to the three months ended December 31, 2017, the Company's second quarter of fiscal 2018."Prior quarter" refers to the three months ended September 30, 2017, the Company's2023, our first quarter of fiscal 2018."year 2024.quarter"quarter” refers to the three months ended December 31, 2016, the Company's second2022, our first quarter of fiscal 2017.Highlights foryear 2023.Quarter:We reported revenuesownership of $11.1 million forand investment in onshore oil and natural gas properties in the current quarter,United States. In support of that objective, our long-term goal is to maximize total shareholder return from a diversified portfolio of long-life oil and natural gas properties built through acquisitions and through selective development opportunities, production enhancements, and other exploitation efforts on our oil and natural gas properties.increaseestablished operator in the geographic region.30% over bothapproximately 39% average net working interest and approximately 33% average net revenue interest located on approximately 43,300 net acres (approximately 92% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota. The properties are operated by Foundation Energy Management, an established operator in the priorgeographic region.year-ago quarters.Current quarterNGL producing shale reservoir, consist of approximately 17% average net income was $9.9 million, or $0.30 per common share, comparedworking 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.incomeworking interest, with an associated 20% average net revenue interest (inclusive of $0.07 per common share in botha small overriding royalty interest). The approximately 5,900 gross acre unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company, who owns the prior and year-ago quarters.Net income for the current quarter included a one-time $6.0 million non-cash tax benefit related to passagemajority of the Tax Cuts and Jobs ActOur realized oil price for the current quarter was $57.30 per barrel, the highest quarterly average since the quarter ended June 30, 2015.We paid our seventeenth consecutive quarterly cash dividend on common shares,amount of $0.075 per share, and announced an increaseHamilton Dome Field. The Hamilton Dome Field is located in the quarterly dividend rate to $0.10 per share forsouthwest region of the quarter ending March 31, 2018.We ended the current quarter with $27.6 million of working capital, an increase of $3.2 million from the prior quarter, after paying $2.5 millionBig Horn Basin in common stock dividends.ProjectsAdditional 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 ProjectfieldField, a CO2-EOR project producing oil and NGLs, consist of a 23.9%approximately 24% average net working interest, (withwith an associated 19.0% net19% revenue interest)interest and separate overriding royalty and mineral interests of 7.2%. This yieldsapproximately 7% yielding a total average net revenue interest of 26.2%approximately 26%. The field is operated by Denbury Onshore LLC (“Denbury”). The Delhi Field is located in northeast Louisiana in Franklin, Madison, and Richland Parishes and encompasses approximately 14,000 gross unitized acres, or approximately 3,200 net acres.
On January 5, 2024, we entered into separate Purchase and Sale Agreements (“PSAs”) with Red Sky Resources III, LLC, Red Sky Resources IV, LLC, and Coriolis Energy Partners I, LLC. Pursuant to the PSAs, we will acquire non-operating working interests in oil and natural gas properties in the SCOOP and STACK plays in central Oklahoma for a combined purchase price of approximately $43.5 million in cash (“the SCOOP/STACK Acquisitions”). Contemporaneous with the execution of the PSAs, we paid deposits totaling $3.26 million. We expect to fund the balance of the consideration to be paid in the transactions with a combination of cash on hand and borrowings under our senior secured credit facility.Gross
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”).production at Delhi inprices falling to historic 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 netstarted 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 increasedrecover primarily as a result of higher realized oil pricesthe roll-out of the COVID-19 vaccine and lessening of pandemic related government restrictions on individuals and businesses.field,Middle East, the military activities of Russia into Ukraine and the subsequent sanctions imposed on Russia and other actions have created significant market uncertainties, including uncertainties around potential supply disruptions for oil and natural gas, which are directly tied to the price per Mcf for purchased CO2. Under our contract with the operator, purchased CO2 is priced at 1%have further enhanced volatility in global commodity prices.realizedU.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.price inand natural gas properties are operated by third-party operators and involve other third-party working interest owners. As a result, we have limited ability to influence the field per thousand cubic feet (“Mcf”) plus sales taxesoperation or future development of 8%such properties. Despite these uncertainties, we remain focused on our long-term objectives and transportation costscontinue to be proactive with our third-party operators to review capital expenditures and present alternative plans as necessary.the prior quarter.2017 Tax Cutscash and Jobs ActOn December 22, 2017, the U.S. government enacted comprehensive tax legislation under the title of the Tax Cutscash equivalents compared to $11.0 million in cash and Jobs Act ("Tax Act"). The Tax Act includes a permanent reduction in our federal corporate income tax rate from 34% to 21%. It also provides more favorable tax deductions associated with capital investments and other significant changes to tax law. The Tax Act became effective upon passage, so our statutory rate for the current fiscal year endedcash equivalents at June 30, 2018 is a blended rate2023. Our primary sources of 27.55%. The permanent reduction inliquidity and capital resources during the federal corporate income tax rate resulted in a one-time non-cash income tax benefit of approximately $6.0 million related to the adjustment of our liability for deferred income taxes to the lower rate in the Tax Act. The accounting for the effects of the rate change on the Company’s deferred tax balances is complete and no provisional amounts were recorded. Three Months Ended
December 31, Six Months Ended
December 31, 2017 2016 2017 2016 Income before income taxes 4,824,637 3,668,731 7,355,491 6,374,682 Income tax (benefit) provision (a) (5,052,211 ) 1,361,097 (4,661,889 ) 2,250,273 Effective tax rate (a) (105 )% 37 % (63 )% 35 % (a) The income tax provision for the three months and six months ended December 31, 2017 includes a one-time non-cash benefit of approximately $6.0 million for2023 were cash provided by operations and the adjustmentunused portion of our liability for deferred income taxes to the lower rate in the Tax Act. This adjustment results in a negative effective tax rate (benefit) for these periods.Income taxes are recorded in our financial statements based on our estimated annual effective income tax rate. The effective rates used in the calculationSenior Secured Credit Facility. Our primary uses of our income tax expense were approximately 21%liquidity and 37%capital resources for the three months ended December 31, 20172023 were cash dividend payments to our common stockholders, capital expenditures on our existing oil and 2016, respectively. Includingnatural gas properties, and initial cash consideration paid for unevaluated oil and natural gas properties under our Participation Agreement with PEDEVCO. As of December 31, 2023, working capital was $6.6 million, a decrease of $2.3 million from working capital of $8.9 million as of June 30, 2023.adjustment forlender based on the $6.0 million discrete benefit resulting from the revaluationvalue of our deferred income tax liabilities,oil and natural gas properties. The Senior Secured Credit Facility has a current borrowing base of $50.0 million. The Senior Secured Credit Facility is secured by substantially all of our oil and natural gas properties and matures on April 9, 2026.effective rate forSOFR plus 2.80% or the quarter ended December 31, 2017 was a tax benefit of (105)% of income before income taxes.ForPrime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%. During the six months ended December 31, 2017 and 2016 the effective rates used in the calculation of2023, we did not have any borrowings outstanding under our income tax expense were approximately 20% and 35% , respectively. Including the adjustment for the $6.0 million discrete benefit resulting from the revaluation of our deferred income tax liabilities, the effective rate for the six months ended December 31, 2017 was a tax benefit of (63)% of income before income taxes.Excluding the impact of the $6.0 million deferred tax adjustment, the effective tax rates for the three months and six months ended December 31, 2017 were lower than the corresponding prior periods as a result of the lower statutory tax rate and higher utilization of percentage depletion in excess of basis during the current year.Liquidity and Capital ResourcesWe had $25.7 million and $23.0 million in cash and cash equivalents at December 31, 2017 and June 30, 2017, respectively.In addition, we have a senior secured reserve-based credit facility (the "Facility") with a maximum capacity of $50.0 million.Senior Secured Credit Facility. The Facility had $10.0 million of borrowing base availability on December 31, 2017 and June 30, 2017, respectively. Effective February 1, 2018, the borrowing base and availability under the Facility was expanded to $40.0 million. There have been no borrowings under the Facility, which matures on April 11, 2019 and is secured by substantially all of the Company’s assets.Any future borrowings bear interest, at the Company's option, at either LIBOR plus 2.75% or the Prime Rate, as defined, plus 1.0%. TheSenior 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 December 31, 2017, the Company was2023, we were in compliance with all covenants containedunder the Senior Secured Credit Facility.Facility.DuringNinth Amendment to the six months ended December 31, 2017, we fundedSenior 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 operationsMargined Collateral Value takes into account the estimated value of our oil and cash dividendsnatural gas properties, proved developed reserves, total indebtedness, and other relevant factors consistent with cash generated from operationscustomary oil and natural gas lending criteria. We expect to be subject to these hedge requirements upon the closing of our cash balance increased $2.7 million during that period. As of December 31, 2017, our working capital was $27.6 million, an increase of $4.2 million over working capital of $23.4 million at June 30, 2017. 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.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 $50.0 million as of December 31, 2023. 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. 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 seventeen41 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. InOn February 2018,5, 2024, the Board of Directors declared an increasea quarterly cash dividend of $0.12 per share of common stock to shareholders of record on March 15, 2024 and payable on March 28, 2024.quarterly common stock dividendopen market through December 31, 2024. We intend to fund any repurchases from $0.075 per shareworking capital and cash provided by operating activities. As we continue to $0.10 per share, effectivefocus 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 paymentpolicy and investment opportunities, and is a tax efficient means to further improve shareholder return.March 2018.the open market subject to pre-defined limitations on trading volume and price. The Board reviewsplan is effective until June 30, 2024, unless extended, renewed or terminated, and has a maximum authorized amount of $0.8 million over that period. We may alter the quarterly dividend rate in lightterms of the plan from time to time to the extent we determine changes are necessary to achieve the intended objectives of our financial position and operations, forecasted results, including the outlook for oil and NGL prices, the timing of further expansion of Delhi development and other potential growth opportunities.2017,2023, we incurred $1.4$5.7 million of capital expenditures at Delhi. This spending included $0.4 million for capital upgrades to the recycle plant, $0.5 million for Phase V infrastructure, $0.4 million for CO2 conformance projects and $0.1 million for otherin capital expenditures.A twelve-well infill During the current quarter, we participated in the drilling programand completion of the initial three wells in the Chaveroo Field. During the first fiscal quarter, we participated in the drilling and completion of two new wells in the Delhi field has been approved and is planned to commence during the quarter ended March 31, 2018. The infill program has a revised estimated net cost of $4.7 million, the majority of whichField. First production at Chaveroo Field is expected in February 2024. Production of the Delhi wells came online in the first fiscal quarter of 2024 and produced consistently in the second fiscal quarter.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 $14.0 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 $2.8 million for water injection, flowlinesyear 2024 include the two new drilled wells at Delhi Field and other infrastructure projectsthree wells at Chaveroo Field, both of which are discussed above. We also expect to start incurring capital expenditures, in preparationthe fourth quarter at Chaveroo Field, for the Phase V pattern development. Approximately $0.5second development block consisting of six horizontal wells. As mentioned in Recent Developments, the Company has entered into three separate definitive agreements to purchase oil and natural gas properties in the SCOOP/STACK plays in central Oklahoma for a combined purchase price of $43.5 million, of these costs have been incurred as of December 31, 2017. In addition, we expect to continue to perform conformance workoverbefore customary closing adjustments. Our budgeted capital expenditures discussed above do not include any potential capital projects and will likely incur additional maintenance capital expenditures. Such amounts cannot be estimated accurately at this time, but are not expected to be material to our financial position.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 ActivitiesNet 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. and Proved Undeveloped ReservesAs 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. 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 December 31, 2023 were $78.21 per barrel of oil, $2.63 per MMBtu of natural gas and $31.57 per barrel of NGLs. As of December 31, 2023, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling. If commodity prices drop below the averageprice levels were to substantially decline from the past twelve months,12-month average first day of the month pricing levels as of December 31, 2023 and remain down for a prolonged period of time, our valuation ceiling over our capitalized costs may be reduced and adversely impact our ceiling tests in future ceiling test calculations would be adversely affected.quarters. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required in the future. Additionally, a 10% reduction in respective commodity prices at December 31, 2023, while all other factors remained constant, would not have generated an impairment. proved undeveloped reserves at June 30, 2017 included 544 MBOEaverage realized price per barrel of reserves and $3.2oil equivalent (“BOE”) decreased $18.37, or 34.1% from the prior year period. Refer to “Results of Operations” below for further information.of future development costs associated with a planned infill drilling program and 1,564 MBOE of reserves and $10.9 million of future development costs associated withcompared to the Phase V development in the eastern portion of the field. The objective of the infill drilling program issix months ended December 31, 2022 due to increase production and recover reserves which are not believed to be effectively producible with the existing well configuration. The project includes both acceleration of production and an increase in ultimate reserve recovery and has been recorded as a proved undeveloped project. The infill project, which was increased from eight wells to twelve wells subsequentcapital expenditures related to the datedrilling and completion of the reserve report, is expected to beginthree new wells in the third quarterChaveroo Field during the current quarter.fiscal 2018. The timingborrowings outstanding under our Senior Secured Credit Facility. For the six months ended December 31, 2023 and 2022, cash dividends paid to our common stockholders were $8.0 million and $8.1 million, respectively.the infill program. At present, we expect to begin this development in calendar 2019.20172023 and 2016sets forth certainsummarizes the comparison of financial information for the periods presented:(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. respecta decrease in our sales volumes. Our average realized commodity price (excluding the impact of derivative contracts) for the three months ended December 31, 2023 decreased approximately $14.24 per BOE, or 28.2%, compared to the prior year period. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, inventory storage levels, basis differentials and other factors. Realized natural gas prices decreased 54.4% from the prior year period, driving the largest decrease in revenues. This was partially attributed to the prior year period benefit of strong natural gas price differentials received at the Jonah Field where we realized an average natural gas price of $11.00 per MCF in the prior year period compared to $4.87 in the current year quarter. Average daily equivalent production decreased 13.0% from 7,250 BOEPD in the prior year period to 6,304 BOEPD in the current period. We began experiencing production declines and downtime in April 2023 at Barnett Shale. Production declines were primarily related to compression issues due to excessive heat, downtime in the gathering and processing system, pipeline rerouting and optimization, and our operator’s decision to temporarily shut-in certain low margin wells. As of December 31, 2023, the midstream issues have been moderated, but due to low natural gas prices the shut-in wells remain offline which has continued to impact production volumes.operations:prices as well as decreased production volumes described above as production taxes are based on sales at the wellhead. Three Months Ended December 31, 2017 2016 Variance Variance % Oil and gas production: Crude oil revenues $ 10,185,635 $ 8,529,817 $ 1,655,818 19.4 % NGL revenues 881,276 — 881,276 n.m. Total revenues $ 11,066,911 $ 8,529,817 $ 2,537,094 29.7 % Crude oil volumes (Bbl) 177,767 182,815 (5,048 ) (2.8 )% NGL volumes (Bbl) 26,033 — 26,033 n.m. Equivalent volumes (BOE) 203,800 182,815 20,985 11.5 % Crude oil (BOPD, net) 1,932 1,987 (55 ) (2.8 )% NGLs (BOEPD, net) 283 — 283 n.m. Equivalent volumes (BOEPD, net) 2,215 1,987 228 11.5 % Crude oil price per Bbl $ 57.30 $ 46.66 $ 10.64 22.8 % NGL price per Bbl 33.85 — 33.85 n.m. Equivalent price per BOE $ 54.30 $ 46.66 $ 7.64 16.4 % $ 1,265,582 $ 1,041,741 $ 223,841 21.5 % All other lease operating expenses 1,648,930 1,250,680 398,250 31.8 % Production costs $ 2,914,512 $ 2,292,421 $ 622,091 27.1 % Production costs per BOE $ 14.30 $ 12.54 $ 1.76 14.0 % 69.7 67.0 2.7 4.0 % Oil and gas DD&A (a) $ 1,626,324 $ 1,299,813 $ 326,511 25.1 % Oil and gas DD&A per BOE $ 7.98 $ 7.11 $ 0.87 12.2 % n.m. Not meaningful.(a) Excludes $7,544$7,697Natural Gas Propertiesother depreciationour unit of production calculation increased due to decreases in proved reserve volumes as well as increases in our depletable base due to capital expenditures since December 31, 2022. Our proved reserves volumes have decreased since the prior year period primarily due to oil and amortizationnatural gas volumes produced combined with a reduction in the SEC prices used in calculating proved reserves since the prior year period.2017 and 2016, respectively.Net Income Available2023 increased $0.1 million to Common Stockholders. During the three months ended December 31, 2017, we generated net income of $9.9$0.6 million or $0.30 per diluted share, on total revenues of $11.1 million. This comparescompared to net income of $2.3$0.5 million or $0.07 per diluted share, on revenues of $8.5 million for the year-ago quarter. The $7.6 million earnings increase reflects a $2.5 million revenue increase, a $6.4 million decline in income taxes primarily attributable to the impact of the 2017 Tax Cuts and Jobs Act, partially offset by $1.4 million of higher operating expenses.Oil and Gas Revenues. Revenues increased 30% to $11.1 million as a result of a 11.5% increase in production volumes from the year-ago quarter, together with a 16% increase in realized oil and NGL prices from $46.66 per equivalent barrel to $54.30 per equivalent barrel in the current quarter. All of our revenues for the current and year-ago quarters came from the Delhi field. Net Delhi oil production volumes of 1,932 BOPD decreased 55 BOPD from the year-ago quarter, as a number of highly successful conformance and production enhancement operations in the prior year stabilized at lower ratesdue to new awards granted during the current year.current quarter. Net NGL production averaged 283 BOEPDmark-to-market valuation of the derivative contracts in the current quarter, at anunaudited condensed consolidated statements of operations. The amounts recorded on the unaudited condensed consolidated statements of operations related to derivative contracts represent the (i) gains (losses) related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) gains (losses) on settlements of derivative contracts for positions that have settled or been realized. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized (gains) losses on our average sales pricerealized prices for the periods presented. As of $33.85 per barrel. ThereDecember 31, 2023, we did not have any open crude oil or natural gas derivative contracts. In the prior year period, because of our acquisitions during fiscal year 2022 and the corresponding borrowings on our Senior Secured Credit Facility, we were no NGL salesrequired by terms set in the year-ago quarter as NGL plant production beganSenior Secured Credit Facility to hedge a portion of our production. The increase in January 2017.Production Costs. Production costscommodity prices since entering into those hedges resulted in realized losses on derivative contracts for the current quarter were $2.9 million, a $0.6 million, or 27%, increase from the year-ago quarter, primarily due to to higher CO2 costs and the incremental operating costsprior year period.Calculated solely on our Delhi working interest volumes, production costs were $18.75 per BOE, of which $8.55 per BOE was CO2 cost. These costs per equivalent barrel exclude production volumes from our royalty interests in the Delhi field, which bear almost no production costs, and are therefore higher than the rates per barrel on our total production volumes.General and Administrative Expenses (“G&A”). G&A expenses increased $0.4 million, or 34%, to $1.72017 as a result2023 compared to the prior year period primarily due to repayments of $0.2borrowings outstanding on our Senior Secured Credit Facility during the prior fiscal year.higher non-cash stock compensation$1.6 million compared to income tax expense $0.1of $2.9 million for litigation costs and $0.1 million for due diligence costs associated with property evaluations.Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A increased $0.3 million, or 25%, to $1.6on net income before income taxes of $13.3 million for the current quarterthree months ended December 31, 2022. The effective tax rates were 33.9% and 22.0% for three months ended December 31, 2023 and 2022, respectively. The effective tax rate increased compared to the year-agoprior year period primarily as projected state income taxes have become a resultlarger component of higher full cost amortization, reflecting an 11% increase in production to 203,800 BOE, together with a 12% higher amortization rateour overall income tax expense during the period.sets forth certainsummarizes the comparison of financial information for the periods presented:(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. respecta decrease in our sales volumes. Our average realized commodity price (excluding the impact of derivative contracts) for the six months ended December 31, 2023 decreased approximately $18.37 per BOE, or 34.1%, over the prior year period. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, inventory storage levels, basis differentials and other factors. Realized natural gas prices decreased 60.3% from the prior year period, driving the largest decrease in revenues. This was partially attributed to the prior year period benefit of strong natural gas price differentials received at the Jonah Field where we realized an average natural gas price of $9.59 per MCF in the prior year period compared to $4.27 in the current year period. Average daily equivalent production decreased 14.0% from 7,418 BOEPD in the prior year period to 6,380 BOEPD in the current period. We began experiencing production declines and downtime in April 2023 at Barnett. Production declines were primarily related to compression issues due to excessive heat, downtime in the gathering and processing system, pipeline rerouting and optimization, and our operator’s decision to temporarily shut-in certain low margin wells. As of December 31, 2023, the midstream issues have been moderated, but due to low natural gas prices the shut-in wells remain offline which has continued to impact production volumes.operations:prices as well as decreased production volumes described above as production taxes are based on sales at the wellhead. Six Months Ended December 31, 2017 2016 Variance Variance % Oil and gas production: Crude oil revenues $ 18,014,890 $ 16,123,672 $ 1,891,218 11.7 % NGL revenues 1,589,892 89 1,589,803 n.m. Natural gas revenues — (4 ) 4 n.m. Total revenues $ 19,604,782 $ 16,123,757 $ 3,481,025 21.6 % Crude oil volumes (Bbl) 344,504 360,817 (16,313 ) (4.5 )% NGL volumes (Bbl) 51,279 4 51,275 n.m. Natural gas volumes (Mcf) — 16 (16 ) n.m. Equivalent volumes (BOE) 395,783 360,824 34,959 9.7 % Crude oil (BOPD, net) 1,872 1,961 (89 ) (4.5 )% NGLs (BOEPD, net) 279 — 279 n.m. Natural gas (BOEPD, net) — — — n.m. Equivalent volumes (BOEPD, net) 2,151 1,961 190 9.7 % Crude oil price per Bbl $ 52.29 $ 44.69 $ 7.60 17.0 % NGL price per Bbl 31.00 22.25 8.75 39.3 % Natural gas price per Mcf — (0.25 ) 0.25 n.m. Equivalent price per BOE $ 49.53 $ 44.69 $ 4.84 10.8 % $ 2,353,843 $ 2,119,874 $ 233,969 11.0 % All other lease operating expenses 3,452,255 2,517,188 935,067 37.1 % Production costs $ 5,806,098 $ 4,637,062 $ 1,169,036 25.2 % Production costs per BOE $ 14.67 $ 12.85 $ 1.82 14.2 % 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 $15,206$15,499Natural Gas Propertiesother depreciationour unit of production calculation increased due to decreases in proved reserve volumes as well as increase in our depletable base due to capital expenditures since December 31, 2022. Our proved reserves volumes have decreased since the prior year period primarily due to oil and amortizationnatural gas volumes produced combined with a reduction in the SEC prices used for calculating proved reserves since the prior year period.20172023 increased $0.3 million to $1.0 million compared to $0.7 million for the prior year period. The increase is primarily due to the addition of new personnel, including our CEO and 2016, respectively.Income AvailableGain (Loss) on Derivative ContractsCommon Stockholders. Duringreduce our exposure to fluctuations in oil and natural gas prices. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the six months endednet change in the mark-to-market valuation of the derivative contracts in the unaudited condensed consolidated statements of operations. The amounts recorded on the unaudited condensed consolidated statements of operations related to derivative contracts represent the (i) gains (losses) related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) gains (losses) on settlements of derivative contracts for positions that have settled or been realized. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized (gains) losses on our average realized prices for the periods presented. As of December 31, 2017,2023, we generated net incomedid not have any open crude oil or natural gas derivative contracts. In the prior year period, because of $12.0 million, or $0.36 per diluted share,our acquisitions during fiscal year 2022 and the corresponding borrowings on total revenuesour Senior Secured Credit Facility, we were required by terms set in the Senior Secured Credit Facility to hedge a portion of $19.6 million. This compares to net income of $2.9 million, or $0.09 per diluted share,our production. The increase in commodity prices since entering into those hedges resulted in realized losses on revenues of $16.1derivative contracts for the prior year period.2016. The $9.1 million earnings increase reflects higher revenues of $3.5 million, an income tax decrease of $6.9 million primarily attributable2023 compared to the impact of Tax Cuts and Jobs Act, and a $1.2 million decrease in allocated net income to holders of preferred shares retired in November 2016, partially offset by $2.5 million of higher operating expenses.Oil and Gas Revenues. Revenues increased 22% to $19.6 million as a result of a 10% increase in production volumes over the prior year period together with a 11% increase in realized prices from $44.69 per equivalent barrel to $49.53 per equivalent barrel. All of our revenues in the current fiscal year came from the Delhi field, as well as virtually all of our revenues from the prior year. Net Delhi oil production volumes of 1,872 BOPD decreased 89 BOPD from the prior year period. Net NGL production averaged 279 BOEPD, at an average price of $31.00 per barrel. There were no NGL sales in the year-ago period as NGL plant production began in January 2017.Production Costs. Production costs for the current year period were $5.8 million, a $1.2 million, or 25%, increase from the same period a year ago, primarily due to higher CO2 costs andrepayments of borrowings outstanding on our Senior Secured Credit Facility during the incremental operating costsprior fiscal year.the NGL plant that commenced operations in January 2017. CO2 costs increased $0.2$1.0 million or 11%, due to higher purchase cost per Mcf, which is derived from the realized field oil price, partially offset by a slight 1% decline in purchase volumes. Average gross purchased 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 costson net income before income taxes of the NGL plant, power, chemicals, repairs and maintenance, labor and overhead, increased $0.9$3.6 million or 37%, from the year-ago period. Virtually all of this increase was attributable to the NGL plant. Production costs per equivalent barrel in the current period were $14.67 per BOE on total production volumes, compared to $12.85 in the prior year period.Calculated solelyincome tax expense of $6.0 million on our Delhi working interest volumes, production costs were $19.24 per BOE,net income before income taxes of which $8.19 per BOE was CO2 cost. These costs per equivalent barrel exclude production volumes from our royalty interests in the Delhi field, which bear almost no production costs, and are therefore higher than the rates per barrel on our total production volumes.General and Administrative Expenses (“G&A”). G&A expenses increased $0.8 million, or 31%, to $3.2$27.1 million for the six months ended December 31, 2017.2022. The increase in expense included $0.4 million of non-cash stock-based compensation expense, $0.1 million of severance costs, $0.1 million of litigation expense, $0.1 million of due diligence costs associated with property evaluations,effective tax rates were 28.5% and $0.1 million of higher board of director expenses.Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A22.1% for three months ended December 31, 2023 and 2022, respectively. The effective tax rate increased $0.6 million, or 22%, to $3.2 million for the current period compared to the year-agoprior year period primarily due to higher full cost amortization, reflectingas projected state income taxes have become a 10% increaselarger component of our overall income tax expense during the period.production to 395,783 BOE, togetheraccordance with a 12% higher amortization rate of $7.93 per BOE. The higher rate is principally due to increased development costs.Other Economic FactorsInflation. 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 condensedoil 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 ArrangementsThe Company had no off-balance sheet arrangements to report for the quarter ended December 31, 2017.ITEM QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKSInformation about market Quantitative and Qualitative Disclosures About Market Risksforincluding 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 RiskOur 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 could be required under full cost accounting rules if future oil and gas commodity prices sustained a significant decline. Prices also affect the amount of cash flow availableprices. We do not enter into derivative contracts for capital expenditures and our abilityspeculative trading purposes.borrow and raise additional capital, as, if and when needed. We may use derivative instruments to manage our exposure to commodity pricemarket risk from time to time based 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 2023 and 2022, we did not post collateral. We account for our derivative activities under the provisions of such risk.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.ITEMCONTROLS AND PROCEDURESforms 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.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 December 31, 20172023 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.the Company’sour management, including its Chiefour Principal Executive Officer and ChiefPrincipal Financial Officer, during the quarter ended December 31, 2017,2023, 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 -ITEMLEGAL PROCEEDINGSWe are involvedLegal ProceedingscertainItem 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.ITEMRISK FACTORS20172023 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.ITEMUNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDSDuring 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.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. quarterthree months ended December 31, 2017.Period October 2017 2,471 $7.03 Not applicable $3.4 million November 2017 29,001 $7.20 Not applicable $3.4 million December 2017 8,262 $7.10 Not applicable $3.4 million Total 39,734 $7.17 Not applicable $3.4 million (1)During the current quarter the Company received shares of common stock from certain of its employees which were surrendered in exchange for their payroll tax liabilities arising from vestings of restricted stock and contingent restricted stock. The acquisition cost per share reflects the weighted-average market price of the Company's shares on the dates vested.(2)On May 12, 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company's common stock. Under the program's terms, shares may be repurchased only on the open market and in accordance with the requirements(1) During the three months ended December 31, 2023, all of the shares received were surrendered by employees in exchange for the payment of tax withholding upon the vesting of restricted stock awards. (2) On September 8, 2022, the Company’s Board of Directors approved a share repurchase program, under which the Company is authorized to repurchase up to $25.0 million of its common stock in the open market through December 31, 2024. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will depend on a variety of factors, including management’s assessment of the intrinsic value of the Company’s shares, the market price of the Company's common stock, the Company’s capital needs and resources, general market and economic conditions, and applicable legal requirements. The value of shares authorized for repurchase by the Company's Board of Directors does not require the Company to repurchase such shares or guarantee that such shares will be repurchased, and the program may be suspended, modified, or discontinued at any time without prior notice. In November 2023, the Company entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan is effective until June 30, 2024, unless extended, renewed or terminated by the Company, and has a maximum authorized amount of $0.8 million over that period. The Company may alter the terms of the plan from time to time to the extent it determines changes are necessary to achieve the intended objectives of the repurchase program. and Exchange Commission. The timing and amount of repurchases will depend upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and the repurchase program may be suspended or discontinued at any time. Such shares are initially recorded as treasury stock, then subsequently canceled.ITEM3. DEFAULTS UPON SENIOR SECURITIESITEM4. MINE SAFETY DISCLOSURESNot applicable.ITEMOTHER INFORMATIONOther InformationNone.ITEMEXHIBITSA.Exhibits4.14.210.131.131.232.132.2101.INS101.SCH101.CAL101.DEF101.LAB101.PREEVOLUTION PETROLEUM CORPORATION(Registrant)By:/s/ RANDALL D. KEYSRandall D. Keys
Date: February 8, 201827