HOUSTON, May 12, 2026 (GLOBE NEWSWIRE) -- Evolution Petroleum Corporation (NYSE American: EPM) ("Evolution" or the "Company") today announced its financial and operating results for its fiscal third quarter ended March 31, 2026. Evolution also declared its 16th consecutive $0.12 cash dividend per common share, payable on June 30, 2026, marking its 51st consecutive quarterly cash dividend payment.
Financial & Operational Highlights
($ in thousands)Q3 2026Q3 2025Q2 2026% Changevs Q3/Q3% Change
vs Q3/Q22026 YTD2025 YTD% Change
vs YTD'25Average BOEPD 6,700 6,667 7,380— (9)% 7,135 7,033 1%Revenues$20,168 $22,561 $20,679(11)% (2)% $62,135 $64,732 (4)%Net Income (Loss)(1)$(8,932) $(2,179) $1,065310% NM $(7,043) $(1,939) 263%Adjusted Net Income (Loss)(1)(2)$(2,941) $806 $257NM NM $(2,892) $701 NMAdjusted EBITDA(3)$3,107 $7,421 $7,994(58)% (61)% $18,402 $1,234 (13)%(1) "NM" means "Not Meaningful."(2) Adjusted Net Income is a non-GAAP financial measure; see the non-GAAP reconciliation schedules to the most comparable GAAP measures at the end of this release for more information.(3) Adjusted EBITDA is Adjusted Earnings Before Interest, Taxes, Depreciation, and Amortization and is a non-GAAP financial measure; see the non-GAAP reconciliation schedules to the most comparable GAAP measures at the end of this release for more information.
- Fiscal Q3 production increased slightly year-over-year to 6,700 barrels of oil equivalent per day (“BOEPD”) from 6,667 BOEPD in the prior year period.
- Production remained stable during the quarter, as contributions from recent acquisitions partially offset weather-related disruptions and downtime.
- Adjusted Net Income (Loss) and Adjusted EBITDA were impacted by:
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- $3.2 million in departure from the prior-year period differentials, including $1.2 million related to prior period adjustments at Delhi Field.
- $2.2 million in realized hedge losses.
- Downtime of over 300 BOEPD related to extreme weather conditions in January, optimization activities at certain facilities and unexpected equipment failures. With these issues resolved, production is substantially restored.
- Returned approximately $4.3 million to shareholders in the form of cash dividends during fiscal Q3.
- Evolution expects 23 wells tied to its Louisiana royalty acquisitions to begin producing in the near term, meaningfully driving revenue and cash flow contributions in fiscal Q4 2026 and onward.
M&A Highlights
- Acquired mineral and royalty interests across multiple Louisiana parishes from December 2025 through March 2026, for a total consideration of approximately $5.0 million, primarily consisting of proved producing wells, drilled but not yet producing wells, and permitted locations.
- These transactions added approximately 350 net royalty acres (“NRA”), including 17 gross PDP locations as of quarter-end, and over 50 gross future locations, most of which is expected to begin producing in the near term, enhancing the Company’s inventory of capital-light assets.
- Subsequent to quarter-end, Evolution high-graded its minerals and royalties portfolio by agreeing to sell longer-dated locations and acquiring cash-flowing properties with near-term upside.
- Agreed to divest a portion of non-core, unproved, mineral acres from its SCOOP/STACK portfolio for total consideration of approximately $3.3 million.
- Acquired an additional 50 NRA in the heart of the Haynesville and Bossier Shales, consisting of PDP’s, DUCs, and near-term locations for approximately $0.5 million.
Management Comments
Kelly Loyd, President and Chief Executive Officer, commented: “We continued to make steady progress during the fiscal third quarter, with contributions from recent acquisitions supporting overall volumes across our diversified portfolio. The quarter included the effects of a combination of items that were either isolated, temporary, or one-time. As these have rolled off, we can already see the powerful effects of combining our long-life, low-decline legacy properties, our higher-margin portfolio additions, and our high-return, low-cost workover projects. As we look to the fiscal 4th quarter and beyond, we expect our underlying performance to reflect the portfolio's true earnings power.
“Operationally, we made encouraging progress across our asset base, identifying impactful opportunities. For example, the TexMex assets offer meaningful near-term upside, with more than 100 net BOEPD of incremental production to be added by the end of our fiscal 4th quarter as ongoing optimization work is completed. At Chaveroo, since quarter-end, we have completed conversion of all but one of our wells from electric submersible pumps ("ESP") to rod pumps, as water production declined as projected, which should reduce operating costs and allow for longer run-times. These are just two of the many impactful optimization projects we are working on with our operators across the portfolio.
“On the acquisition front, we continued executing on our mineral and royalty strategy. During the quarter, we expanded our Louisiana position in the Haynesville and Bossier Shales. These assets are being actively developed by operators in the area and provide capital-light exposure to substantial future development. We continue to see highly accretive bolt-on opportunities to build scale and expect contributions from these high-margin positions to grow over time as completion activity progresses with no additional development cost to the Company. We also agreed to divest non-core mineral acreage having more distant future development plans and reinvest into near-term opportunities with clearer visibility of revenue and cash flow contributions beginning in fiscal 2027.
“Looking ahead, we remain committed to our long-standing capital allocation framework and believe we are well positioned to protect the balance sheet, support a dividend that we have maintained for more than 50 consecutive quarters, which we believe is durable through cycles, deploy capital where we see compelling risk-adjusted returns, and continue compounding long-term value for our shareholders.”
Fiscal Third Quarter 2026 Financial Results
Total revenues decreased 11% to $20.2 million compared to $22.6 million in the year-ago quarter. The change was driven primarily by an 11% decrease in average realized equivalent prices, partially offset by a slight increase in average daily production. The current quarter oil revenue at Delhi Field was materially impacted by a one-time $1.2 million prior-period adjustment for transportation charges, due to a new marketing contract entered into by the operator in December 2024 and not communicated to the Company until the current quarter. The Company is reviewing responses to these actions and is evaluating alternative marketing options going forward. During the current quarter, decreases in natural gas revenues were driven by unfavorable natural gas field differentials. At Jonah Field in particular, the historically warm winter on the West Coast led to differentials declining by $1.96 per Mcf on average compared to the year-ago period. Barnett Shale also experienced more unfavorable differentials than last year, declining by $0.90 per Mcf below the year-ago period.
Lease operating costs (“LOE”) improved to $13.0 million compared to $13.4 million in the year-ago quarter. The decrease was primarily driven by the cessation of CO2 purchases at Delhi Field, partially offset by the addition of TexMex properties and initial workover and facility upgrades in the field. On a per-unit basis, LOE was $21.49 per BOE compared to $22.32 per BOE in the year-ago quarter. The addition of our recently acquired Oklahoma and Louisiana Minerals properties contributed to the lower per-unit LOE as they provide a higher-margin asset base with no lifting costs.
Depletion, depreciation, and accretion expense was $5.3 million compared to $5.0 million in the year-ago period. On a per-BOE basis, the Company’s current quarter depletion rate was $8.13 per BOE, compared to $7.68 per BOE in the year-ago period.
General and administrative (“G&A”) expenses (excluding stock-based compensation) remained flat at $1.9 million for each period. On a per-BOE basis, G&A (excluding stock-based compensation) was $3.11 compared to $3.22 in the year-ago period.
The Company reported net loss of $8.9 million, or ($0.26) per diluted share, compared to net loss of $2.2 million, or $(0.07) per diluted share, in the year-ago period, primarily driven by unrealized losses on future period hedges extending into calendar 2027. Excluding the impact of selected items, which include losses on the unrealized portion of hedges, the Company reported adjusted net loss of $2.9 million, compared to adjusted net income of $0.8 million in the year-ago period.(1)
Adjusted EBITDA was $3.1 million compared to $7.4 million in the year-ago quarter. The decrease was primarily due to historically high unfavorable natural gas field differentials, the aforementioned prior-period adjustments at Delhi, and realized losses on derivative contracts, compared to the prior-year period.(2)
Production & Pricing
Average price per unit:Q3 2026Q3 2025% Change vs Q3/Q3Crude oil (BBL)$59.18$68.42(14)%Natural gas (MCF) 3.70 3.87(4)%Natural Gas Liquids (BBL) 24.59 32.28(24)%Equivalent (BOE) 33.45 37.60(11)%Total production for the third quarter of fiscal 2026 increased slightly to 6,700 net BOEPD compared to 6,667 net BOEPD in the year-ago period. Total production for the third quarter of fiscal 2026 included approximately 1,967 barrels per day (“BOPD”) of crude oil, 3,644 BOEPD of natural gas, and 1,089 BOEPD of NGLs. The change in total production was primarily driven by production adds from the Company’s SCOOP/STACK Minerals Acquisition in August 2025 and TexMex Acquisition in April 2025, partially offset by downtime at other fields. In January 2026, multiple fields were impacted by heavy ice storms and power outages, resulting in production shutdowns for multiple days.
The Company’s average realized commodity price (excluding the impact of derivative contracts) decreased to $33.45 per BOE in fiscal Q3, compared to $37.60 per BOE in the year-ago period. The aforementioned Delhi prior-period adjustments reduced the Company’s average realized equivalent price for the quarter by approximately $1.90 per BOE. Compared with the prior-year period, unfavorable gas differentials at Jonah and Barnett reduced the Company’s average realized equivalent price for the quarter by approximately $3.39 per BOE.
Operations Update
The Company continued to expand its mineral and royalty position, completing two mineral acreage acquisitions in the Haynesville and Bossier Shales in Louisiana during fiscal Q3, following two similar acquisitions completed in fiscal Q2. The Company’s mineral acquisitions prioritize placing value on wells that are either currently producing or are expected to be producing within one year of purchase. We expect 23 wells to be brought online and meaningfully contribute to revenue and cash flow in the fiscal fourth quarter.
At SCOOP/STACK, quarterly production was impacted by 64 BOEPD due to the winter storm in January. Additionally, there are 7 gross wells in progress and 12 gross wells on production that we are still waiting for first production data and revenue. Production from mineral and royalty interests acquired in August 2025 continued to contribute to overall volumes during the quarter, leading to a material increase of 27% in production and 24% decrease in LOE per BOE during the current fiscal quarter compared to the prior-year quarter.
At Chaveroo, the January winter storm and gas interference on an ESP affected production by 30 net BOEPD for the quarter. Subsequent to quarter-end, we converted that well from ESP to a rod pump, and all but one of our 7 wells have now been converted to rod pumps. The Company expects to secure permits for its next drilling block, comprising six gross wells, before the end of the 4th fiscal quarter.
At TexMex, oil production increased quarter over quarter due to a successful workover program at the end of the prior quarter. However, January winter storms not only impacted production but also caused power outages and surface equipment damage that required repairs. This led to higher expenses in the quarter. We expect TexMex to continue to improve substantially. Subsequent to quarter-end, we began a new workover program, which we expect will increase production by an additional 100 net BOEPD by the end of fiscal Q4.
At the Williston Basin, production was down 32 BOEPD, due to downtime caused by the January winter storm and delays in crude oil trucking. Operations were quickly restored, and the field runtimes remain strong.
At Barnett, quarterly production was heavily impacted by the winter storm, resulting in a decline of approximately 160 BOEPD. The impacts carried into February and were restored by March.
At Delhi, the January winter storm outages impacted production for 6 days during the quarter. The CO₂ recycle compressor, which was down for most of the prior quarter, remained down for 40 days during fiscal Q3, negatively affecting production. These issues were resolved during the quarter, and we expect to see the benefits of a return to normal run times and restoring full CO₂ recycle capacity moving forward.
Balance Sheet, Liquidity, and Capital Spending
On March 31, 2026, the Company had cash and cash equivalents of $2.6 million, outstanding borrowings of $56.5 million, and $0.8 million in letters of credit outstanding under its Senior Secured Credit Facility, and a weighted average interest rate of 6.78%. Availability under the facility was $7.7 million, bringing total liquidity to $10.4 million. In the third quarter of fiscal 2026, Evolution paid $4.3 million in common stock dividends and incurred $1.6 million in capital expenditures. Evolution also deployed capital on royalty and minerals acquisitions in Louisiana. These cash outlays were partially offset by cash received from its SCOOP/STACK Minerals Acquisition due to purchase price adjustments associated with net cash flows between the effective date and closing date. Evolution also received net proceeds of $3.6 million, net of $0.1 million of offering costs paid, from the sale of shares of common stock under its At-The-Market equity sales agreement. The Company had total net cash provided by operating activities of $3.5 million for the quarter.
Cash Dividend on Common Stock
On May 11, 2026, Evolution's Board of Directors declared a cash dividend of $0.12 per share of common stock, payable on June 30, 2026, to common stockholders of record on June 15, 2026. This will be the 51st consecutive quarterly cash dividend on the Company's common stock since December 31, 2013. To date, Evolution has returned approximately $147.4 million, or $4.41 per share, back to stockholders in common stock dividends.
Conference Call
As previously announced, Evolution Petroleum will host a conference call on Wednesday, May 13, 2026, at 10:00 a.m. CT to review its fiscal third quarter 2026 financial and operating results. Participants can join online at https://event.choruscall.com/mediaframe/webcast.html?webcastid=wK31ZL1A or by dialing (844) 481-2813. Dial-in participants should ask to join the Evolution Petroleum Corporation call. A replay will be available through May 13, 2027, via the provided webcast link and on Evolution's Investor Relations website at www.ir.evolutionpetroleum.com.
About Evolution Petroleum
Evolution Petroleum Corporation is an independent energy company focused on maximizing total shareholder returns through the ownership of and investment in onshore oil and natural gas properties in the U.S. The Company aims to build and maintain a diversified portfolio of long-life oil and natural gas properties through acquisitions, selective development opportunities, production enhancements, and other exploitation efforts. Visit www.evolutionpetroleum.com for more information.
Cautionary Statement
All forward-looking statements contained in this press release regarding the Company's current and future expectations, potential results, and plans and objectives involve a wide range of risks and uncertainties. Statements herein using words such as "anticipate," "believe," "expect," "may," "plans," "outlook," "should," "will," and words of similar meaning are forward-looking statements. Although the Company's expectations are based on business, engineering, geological, financial, and operating assumptions that it believes to be reasonable, many factors could cause actual results to differ materially from its expectations. The Company gives no assurance that its goals will be achieved. These factors and others are detailed under the heading "Risk Factors" and elsewhere in our periodic reports filed with the Securities and Exchange Commission ("SEC"). The Company undertakes no obligation to update any forward-looking statement.
Contact
Investor Relations
(713) 935-0122
[email protected]
Condensed Consolidated Statements of Operations (Unaudited)
(In thousands, except per share amounts) Three Months Ended Nine Months Ended March 31, December 31, March 31, 2026 2025 2025 2026 2025 Revenues Crude oil $10,474 $11,769 $10,696 $34,042 $38,269 Natural gas 7,284 7,790 7,441 20,625 17,868 Natural gas liquids 2,410 3,002 2,542 7,468 8,595 Total revenues 20,168 22,561 20,679 62,135 64,732 Operating costs Lease operating costs 12,959 13,388 11,510 37,556 37,971 Depletion, depreciation, and accretion 5,294 5,014 5,919 17,174 16,172 General and administrative expenses 2,473 2,573 2,592 7,390 7,754 Total operating costs 20,726 20,975 20,021 62,120 61,897 Income (loss) from operations (558) 1,586 658 15 2,835 Other income (expense) Net gain (loss) on derivative contracts (9,869) (3,802) 2,235 (5,453) (3,223)Interest and other income 24 55 12 46 164 Interest expense (960) (705) (1,003) (2,880) (2,292)Income (loss) before income taxes (11,363) (2,866) 1,902 (8,272) (2,516)Income tax (expense) benefit 2,431 687 (837) 1,229 577 Net income (loss) $(8,932) $(2,179) $1,065 $(7,043) $(1,939)Net income (loss) per common share: Basic $(0.26) $(0.07) $0.03 $(0.22) $(0.07)Diluted $(0.26) $(0.07) $0.03 $(0.22) $(0.07)Weighted average number of common shares outstanding: Basic 34,315 33,433 33,904 33,979 33,027 Diluted 34,315 33,433 34,025 33,979 33,027
Condensed Consolidated Balance Sheets (Unaudited)
(In thousands, except share and per share amounts) March 31, 2026 June 30, 2025Assets Current assets Cash and cash equivalents $2,616 $2,507Receivables from crude oil, natural gas, and natural gas liquids revenues 9,506 10,804Derivative contract assets 2,428 1,777Prepaid expenses and other current assets 1,983 2,287Total current assets 16,533 17,375Property 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 147,998 142,248Oil and natural gas properties, not subject to amortization 3,804 —Total property and equipment, net 151,802 142,248 Other noncurrent assets Derivative contract assets 634 198Other assets, net 791 431Total assets $169,760 $160,252Liabilities and Stockholders' Equity Current liabilities Accounts payable $12,588 $12,901Accrued liabilities and other 5,619 6,909Derivative contract liabilities 8,514 1,577State and federal taxes payable 425 —Total current liabilities 27,146 21,387Long term liabilities Senior secured credit facility 56,500 37,500Deferred income taxes 3,829 6,234Asset retirement obligations 22,700 21,535Derivative contract liabilities 808 1,783Operating lease liability 369 —Total liabilities 111,352 88,439Commitments and contingencies Stockholders' equity Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 35,821,410 and 34,337,188 shares as of March 31, 2026 and June 30, 2025, respectively 36 34Additional paid-in capital 52,899 46,650Retained earnings 5,473 25,129Total stockholders' equity 58,408 71,813Total liabilities and stockholders' equity $169,760 $160,252
Condensed Consolidated Statements of Cash Flows (Unaudited)
(In thousands) Three Months Ended Nine Months Ended March 31, December 31, March 31, 2026 2025 2025 2026 2025 Cash flows from operating activities: Net income (loss) $(8,932) $(2,179) $1,065 $(7,043) $(1,939)Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depletion, depreciation, and accretion 5,294 5,014 5,919 17,174 16,172 Stock-based compensation 595 642 613 1,745 1,860 Settlement of asset retirement obligations (51) (66) (161) (231) (346)Deferred income taxes (1,106) (2,101) (913) (2,405) (2,130)Unrealized (gain) loss on derivative contracts 7,621 3,926 (1,443) 4,875 3,426 Accrued settlements on derivative contracts 688 (57) 375 678 (114)Amortization of debt issuance costs 39 — 39 117 — Other 7 (4) (5) (1) (7)Changes in operating assets and liabilities: Receivables from crude oil, natural gas, and natural gas liquids revenues 74 (26) (1,046) 1,583 (34)Prepaid expenses and other current assets (1,120) 965 157 239 1,400 Accounts payable, accrued liabilities and other 1,227 1,149 (392) (437) 4,382 State and federal taxes payable (847) — 1,217 425 (74)Net cash provided by operating activities 3,489 7,263 5,425 16,719 22,596 Cash flows from investing activities: Acquisition deposits — (1,800) — — (1,800)Acquisition of oil and natural gas properties (4,662) (20) 222 (21,308) (351)Capital expenditures for oil and natural gas properties (1,263) (4,404) (839) (5,920) (7,902)Net cash used in investing activities (5,925) (6,224) (617) (27,228) (10,053)Cash flows from financing activities: Common stock dividends paid (4,261) (4,109) (4,195) (12,613) (12,224)Common stock repurchases, including stock surrendered for tax withholding (43) (71) (50) (225) (262)Borrowings under senior secured credit facility 2,000 — 2,500 22,000 — Repayments of senior secured credit facility — (4,000) (1,000) (3,000) (4,000)Debt issuance costs — — — (379) — Issuance of common stock 3,672 1,145 1,006 4,944 3,404 Offering costs (78) (70) (21) (109) (306)Net cash provided by (used in) financing activities 1,290 (7,105) (1,760) 10,618 (13,388)Net increase (decrease) in cash and cash equivalents (1,146) (6,066) 3,048 109 (845)Cash and cash equivalents, beginning of period 3,762 11,667 714 2,507 6,446 Cash and cash equivalents, end of period $2,616 $5,601 $3,762 $2,616 $5,601
Non-GAAP Reconciliation – Adjusted EBITDA (Unaudited)
(In thousands) Adjusted EBITDA and Net income (loss) and earnings per share excluding selected items are non-GAAP financial measures that are used as supplemental financial measures by our management and by external users of our financial statements, such as investors, commercial banks, and others, to assess our operating performance as compared to that of other companies in our industry, without regard to financing methods, capital structure, or historical costs basis. We use these measures to assess our ability to incur and service debt and fund capital expenditures. Our Adjusted EBITDA and Net income (loss) and earnings per share, excluding selected items, should not be considered alternatives to net income (loss), operating income (loss), cash flows provided by (used in) operating activities, or any other measure of financial performance or liquidity presented in accordance with U.S. GAAP. Our Adjusted EBITDA and Net income (loss) and earnings per share excluding selected items may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA and Net income (loss) and earnings per share excluding selected items in the same manner.
We define Adjusted EBITDA as net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion, and accretion (DD&A), stock-based compensation, ceiling test impairment, and other impairments, unrealized loss (gain) on change in fair value of derivatives, and other non-recurring or non-cash expense (income) items. Three Months Ended Nine Months Ended March 31, December 31, March 31, 2026 2025 2025 2026 2025 Net income (loss) $(8,932) $(2,179) $1,065 $(7,043) $(1,939)Adjusted by: Interest expense 960 705 1,003 2,880 2,292 Income tax expense (benefit) (2,431) (687) 837 (1,229) (577)Depletion, depreciation, and accretion 5,294 5,014 5,919 17,174 16,172 Stock-based compensation 595 642 613 1,745 1,860 Unrealized loss (gain) on derivative contracts 7,621 3,926 (1,443) 4,875 3,426 Adjusted EBITDA $3,107 $7,421 $7,994 $18,402 $21,234
Non-GAAP Reconciliation – Adjusted Net Income (Unaudited)
(In thousands, except per share amounts) Three Months Ended Nine Months Ended March 31, December 31, March 31, 2026 2025 2025 2026 2025 As Reported: Net income (loss), as reported $(8,932) $(2,179) $1,065 $(7,043) $(1,939) Impact of Selected Items: Unrealized loss (gain) on commodity contracts 7,621 3,926 (1,443) 4,875 3,426 Selected items, before income taxes $7,621 $3,926 $(1,443) $4,875 $3,426 Income tax effect of selected items(1) 1,630 941 (635) 724 786 Selected items, net of tax $5,991 $2,985 $(808) $4,151 $2,640 As Adjusted: Net income (loss), excluding selected items(2) $(2,941) $806 $257 $(2,892) $701 Undistributed earnings allocated to unvested restricted stock (105) (96) (104) (291) (274)Net income (loss), excluding selected items for earnings per share calculation $(3,046) $710 $153 $(3,183) $427 Net income (loss) per common share — Basic, as reported $(0.26) $(0.07) $0.03 $(0.22) $(0.07)Impact of selected items 0.17 0.09 (0.03) 0.13 0.08 Net income (loss) per common share — Basic, excluding selected items(2) $(0.09) $0.02 $— $(0.09) $0.01 Net income (loss) per common share — Diluted, as reported $(0.26) $(0.07) $0.03 $(0.22) $(0.07)Impact of selected items 0.17 0.09 (0.03) 0.13 0.08 Net income (loss) per common share — Diluted, excluding selected items(2)(3) $(0.09) $0.02 $— $(0.09) $0.01
(1) The tax impact for the three months ended March 31, 2026, and 2025, is represented using estimated tax rates of 21.4% and 24.0%, respectively. The tax impact for the three months ended December 31, 2025, is represented using estimated tax rates of 44.0%. The tax impact for the nine months ended March 31, 2026, and 2025, is represented using estimated tax rates of 14.9% and 22.9%, respectively.(2) Net income (loss) and earnings per share excluding selected items are non-GAAP financial measures presented as supplemental financial measures to enable a user of the financial information to understand the impact of these items on reported results. These financial measures should not be considered an alternative to net income (loss), operating income (loss), cash flows provided by (used in) operating activities, or any other measure of financial performance or liquidity presented in accordance with U.S. GAAP. Our Adjusted Net Income (Loss) and earnings per share may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted Net Income (Loss) and earnings per share in the same manner.(3) The impact of selected items for the three months ended March 31, 2026, and 2025, were each calculated based upon weighted average diluted shares of 34.3 million and 33.6 million, respectively, due to the net income (loss), excluding selected items. The impact of selected items for the three months ended December 31, 2025, was calculated based upon weighted average diluted shares of 34.0 million due to the net income (loss), excluding selected items. The impact of selected items for the nine months ended March 31, 2026, and 2025, were each calculated based upon weighted average diluted shares of 34.0 million and 33.2 million, respectively, due to the net income (loss), excluding selected items.
Supplemental Information on Oil and Natural Gas Operations (Unaudited)
(In thousands, except per unit and per BOE amounts) Three Months Ended Nine Months Ended March 31, December 31, March 31, 2026 2025 2025 2026 2025Revenues: Crude oil $10,474 $11,769 $10,696 $34,042 $38,269Natural gas 7,284 7,790 7,441 20,625 17,868Natural gas liquids 2,410 3,002 2,542 7,468 8,595Total revenues $20,168 $22,561 $20,679 $62,135 $64,732 Lease operating costs: Ad valorem and production taxes $1,317 $1,473 $588 $3,325 $4,328Gathering, transportation, and other costs 2,834 2,913 2,667 8,393 8,592Other lease operating costs 8,808 9,002 8,255 25,838 25,051Total lease operating costs $12,959 $13,388 $11,510 $37,556 $37,971 Depletion of full cost proved oil and natural gas properties $4,900 $4,607 $5,532 $15,992 $14,956 Production: Crude oil (MBBL) 177 172 193 577 555Natural gas (MMCF) 1,968 2,011 2,241 6,359 6,364Natural gas liquids (MBBL) 98 93 112 318 311Equivalent (MBOE)(1) 603 600 679 1,955 1,927Average daily production (BOEPD)(1) 6,700 6,667 7,380 7,135 7,033 Average price per unit:(2) Crude oil (BBL) $59.18 $68.42 $55.42 $59.00 $68.95Natural gas (MCF) 3.70 3.87 3.32 3.24 2.81Natural Gas Liquids (BBL) 24.59 32.28 22.70 23.48 27.64Equivalent (BOE)(1) $33.45 $37.60 $30.46 $31.78 $33.59 Average cost per unit: Ad valorem and production taxes $2.18 $2.46 $0.87 $1.70 $2.25Gathering, transportation, and other costs 4.70 4.86 3.93 4.29 4.46Other lease operating costs 14.61 15.00 12.16 13.22 13.00Total lease operating costs $21.49 $22.32 $16.96 $19.21 $19.71 Depletion of full cost proved oil and natural gas properties $8.13 $7.68 $8.15 $8.18 $7.76(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.
Summary of Production Volumes and Average Sales Price (Unaudited) Three Months Ended March 31, December 31, 2026 2025 2025 Volume Price Volume Price Volume PriceProduction: Crude oil (MBBL) SCOOP/STACK 27 $69.24 28 $71.36 30 $58.86Chaveroo Field 20 63.87 8 56.78 26 53.39Jonah Field 6 63.70 7 67.69 7 52.95Williston Basin 28 64.57 34 64.35 31 52.15Barnett Shale 2 66.12 3 68.03 2 55.34Hamilton Dome Field 32 57.23 34 58.88 34 47.23Delhi Field 43 43.24 58 76.04 48 61.78TexMex 17 70.47 — — 15 58.24Other 2 57.25 — — — —Total 177 $59.18 172 $68.42 193 $55.42Natural gas (MMCF) SCOOP/STACK 389 $4.13 317 $4.91 458 $3.56Jonah Field 675 3.45 758 4.02 728 3.38Williston Basin 24 3.28 32 3.89 28 2.46Barnett Shale 801 3.87 904 3.39 925 3.21TexMex 59 1.97 — — 102 3.14Other 20 2.88 — — — —Total 1,968 $3.70 2,011 $3.87 2,241 $3.32Natural gas liquids (MBBL) SCOOP/STACK 27 $19.01 13 $27.84 28 $19.90Jonah Field 8 25.50 8 32.14 8 23.10Williston Basin 7 18.47 8 23.74 7 14.13Barnett Shale 47 28.49 49 33.48 55 25.38Delhi Field 9 23.36 15 37.20 14 23.17Total 98 $24.59 93 $32.28 112 $22.70Equivalent (MBOE)(1) SCOOP/STACK 119 $33.66 94 $41.90 134 $29.37Chaveroo Field 20 63.87 8 56.78 26 53.39Jonah Field 127 23.12 141 26.63 136 22.02Williston Basin 39 52.02 47 53.08 43 41.46Barnett Shale 183 25.09 203 24.13 212 21.18Hamilton Dome Field 32 57.23 34 58.88 34 47.23Delhi Field 52 39.44 73 68.19 62 53.30TexMex 27 49.03 — — 32 37.50Other 4 19.85 — — — —Total 603 $33.45 600 $37.60 679 $30.46Average daily production (BOEPD)(1) SCOOP/STACK 1,322 1,044 1,457 Chaveroo Field 222 89 283 Jonah Field 1,411 1,567 1,478 Williston Basin 433 522 467 Barnett Shale 2,033 2,256 2,303 Hamilton Dome Field 356 378 370 Delhi Field 578 811 674 TexMex 300 — 348 Other 45 — — Total 6,700 6,667 7,380 (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.
Summary of Average Production Costs (Unaudited) Three Months Ended March 31, December 31, 2026 2025 2025 Amount Price Amount Price Amount PriceProduction costs (in thousands, except per BOE): Total lease operating costs(1) SCOOP/STACK $1,064 $8.96 $1,106 $11.74 $1,040 $7.72Chaveroo Field 320 15.92 128 15.77 311 12.07Jonah Field 2,047 16.21 2,184 15.51 1,998 14.68Williston Basin 1,162 30.09 1,476 31.45 1,296 30.29Barnett Shale 3,747 20.49 3,739 18.47 2,937 13.98Hamilton Dome Field 1,226 37.73 1,237 36.36 1,200 35.56Delhi Field 1,836 34.13 3,518 48.04 1,506 24.26TexMex 1,557 57.61 — — 1,222 38.03Total $12,959 $21.49 $13,388 $22.32 $11,510 $16.96(1) Total lease operating costs includes lifting costs; workover expenses; and gathering, transportation, processing and other expenses.
Summary of Open Derivative Contracts (Unaudited) For more information on the Company's hedging practices, see Note 7 to its financial statements included on Form 10-Q filed with the SEC for the quarter ended March 31, 2026.
The Company has the following open crude oil and natural gas derivative contracts: Volumes in Weighted Average Price per MMBTU/BBLPeriod Commodity Instrument MMBTU/BBL Swap Sub Floor Floor CeilingApril 2026 - September 2026 Crude Oil Fixed-Price Swap 140,441 $ 60.24 January 2027 - December 2027 Crude Oil Fixed-Price Swap 108,222 65.12 April 2026 - December 2026 Crude Oil Two-Way Collar 115,372 $ 56.33 $ 64.11January 2027 - December 2027 Crude Oil Two-Way Collar 138,157 58.13 69.37September 2026 - December 2026 Crude Oil Three-Way Collar 67,002 $ 50.00 58.83 70.36April 2026 - December 2026 Natural Gas Fixed-Price Swap 2,532,778 3.62 January 2027 - December 2027 Natural Gas Fixed-Price Swap 1,537,008 3.54 April 2026 - December 2026 Natural Gas Two-Way Collar 1,749,713 3.55 4.65January 2027 - March 2027 Natural Gas Two-Way Collar 850,794 3.62 5.60
(1) Adjusted net income (loss) is a non-GAAP financial measure; see the non-GAAP reconciliation schedules to the most comparable GAAP measures at the end of this release for more information.
(2) Adjusted EBITDA is Adjusted Earnings Before Interest, Taxes, Depreciation, and Amortization and is a non-GAAP financial measure; see the non-GAAP reconciliation schedules to the most comparable GAAP measures at the end of this release for more information.