EPM 10-K & 10-Q changes, risk factors and insider trading

●social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States, such as the conflict between Ukraine and Russia and the conflict betweenin Israelthe andMiddle Gaza,East, and acts of terrorism or sabotage;

OurBesides our royalty and mineral interest, our business plan focuses on the acquisition and development of known resources in partially depleted, naturally fractured, or low permeability reservoirs. Our TexMex, Chaveroo Field, Hamilton Dome Field and Delhi Field properties produce from relatively shallow reservoirs, while our SCOOP/STACK, Jonah Field, Williston Basin and Barnett Shale properties produce from deeper reservoirs. Shallower reservoirs usually have lower pressure, which generally translates into lower reserves volumes in place. Deeper reservoirs have higher pressures and usually more reserves volumes in place, but capturing those reserves often comes at increased drilling and completion costs and risks and, generally, a higher rate of initial production decline. Low permeability reservoirs require substantial stimulation for development of commercial production. Naturally fractured reservoirs require penetration of sufficient un-depleted fractures to establish commercial production. Depleted reservoirs require successful application of newer, or more expensive, technologies to produce incremental reserves. Our approach on the development and application of technologies on these different types of reservoirs could have a material adverse effect on our results of operations.

We have limited control over the activities on our oil and natural gas properties which we do not operate.

All of our propertyproved undeveloped oil and natural gas properties, consisting both of working interests and mineral and royalty interests, are operated by others.third-parties. AsThe adevelopment result,and production of our proved undeveloped reserves depend on the decisions and actions of third-party operators, over which we have limited or no control, and their decisions may not be in our best interests. We have limited ability to influence or control the operations or future development of such properties, including compliance with environmental, safety, and other standards, or the amount or timing of capital or other expenditures that we will be required to fund with respect to such properties. OperatorsDeveloping these reserves requires significant capital expenditures and successful drilling operations, and our third-party operators may determine not to develop particular locations or may delay, modify or otherwise alter their development plans for reasons beyond our control. As a result, our proved undeveloped reserves may not be developed or produced as anticipated, or at all. Any delays or changes in development and production by our third-party operators could result in significant fluctuation in the timing and amount of theserevenues propertiesgenerated may act in ways that are not inby our bestoil interest.and natural gas properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs, result in lower production, and materially and adversely affect our financial condition and results of operations.

Cash flow from our production varies based on commodity prices and may decline along with naturenatural declines in our production. As a consequence, our cash flow may not be sufficient to fund our ongoing or planned activities at all times. From time to time, we may require additional financing in order to fund operations, acquisitions, exploitation, and development activities. We have, for instance, accessed our Senior Secured Credit Facility on a routine basis, including, recently, to fund acquisitions. Subsequent to our Permian Minerals Acquisition in August 2026, Louisiana Minerals acquisitions in December 2025 through June 2026, SCOOP/STACK Minerals Acquisition in August 2025, TexMex Acquisition in April 20252025, and the SCOOP/STACK Acquisitions in 2024, the borrowings outstanding on our Senior Secured Credit Facility at JuneSeptember 30,16, 20252026 was $37.5$60.0 million. On June 30, 2025, we entered into aOur syndicated amended and restated credit facility with MidFirst as administrative agent and added a second lender. The commitment size of the Senior Secured Credit Facility washad a commitment size of $65.0 million at June 30, 2026; but in accordance with our letter agreement with MidFirst on August 20, 2026 our syndicated Senior Secured Credit Facility currently has an increased commitment size of $73.0 million until October 20, 2026 when it reverts back to $65.0 millionmillion, fromunless $50.0redetermined million.in accordance with the terms of our credit agreement. We may not be able to further increase the total commitments by adding additional lenders in the future on terms that are favorable to us. Further, the size of our Senior Secured Credit Facility is influenced by many factors, including our production, reserves and prevailing views on future commodity prices, and it may decrease based on developments negatively impacting those and other factors. While ordinarily positive developments in such factors might increase the amount that lenders are willing to lend to us, we are currently at the limit of our two lenders to increase the size of our Senior Secured Credit Facility due to limitations that the lenders have on the loans they may extend to a single borrower. Additionally, access to debt and equity capital markets or other alternatives may also prove unavailable or unattractive at such times or in such amounts as we may require. If we are unable to access adequate capital at acceptable costs, it could adversely affect our ability to expend the necessary capital to replace our reserves, maintain our production and execute our business plans.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing, and financial activities. We depend on digital technology to estimate quantities of oil and natural gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party operators. Our technologies, systems, networks, seismic data, reserves information, or other proprietary information, and those of our operators, vendors, suppliers, customers, and other business partners may become the target of cyber-attacks or information security breaches. Cyber-attacks or information security breaches could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations or other operational disruptions in our exploration or production operations. Cyber-attacksCyber-attacks, particularly amidst the increased adoption of artificial intelligence technologies, are becoming more sophisticated and include, but are not limited to, ransomware, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic synthetic media generated by artificial intelligence) and other attempts to gain unauthorized access to data for purposes of extortion or other malfeasance. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended periodperiod. andAny such attacks could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation, or potential liability. Also, computers control nearly all of the oil and natural gas distribution systems in the United States and abroad. Computers are necessary to transport our oil and natural gas production to market. A cyber-attack directed at oil and natural gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the United States government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against cybersecurity risks may not be sufficient. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

We cannot market the oil and natural gas that we produce without the assistance of third-parties.third parties.

As of June 30, 2025,2026, our executive officers and directors, in the aggregate, beneficially owned approximately 3.43.6 million shares, or approximately 9.9%10.0% of our outstanding common stock and, based on recent filings with the SEC, we believe two large non-affiliated fundinvestment complexesadvisors owned in excess of 12%12.8% of the outstanding shares of our common stock. As a result, a significant percentage of our common stock is concentrated in the hands of relatively few shareholders. These shareholders could potentially exercise significant influence over matters submitted to our stockholders for approval (including the election and removal of directors and any merger, consolidation or sale of all or substantially all of our assets). This concentration of ownership may have the effect of delaying, deferring, or preventing any matter that requires shareholder approval, including a change in control of our company, impede a merger, consolidation, takeover, or other business combination involving our company or discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of our company, which in turn could have an adverse effect on the market price of our common stock.

Our oil and natural gas properties consist primarily of non-operated working and mineral interests in the following areas (as well as small overriding royalty and mineral interests in four onshore central Texas wells):

On August 4,20, 2025,2026, we completed the acquisition of certain mineral and royalty interests in the SCOOP/STACKcore areaMidland Basin of Oklahomathe Permian Basin from a non-affiliated private seller for a total purchase price of $16.0 million (the “Permian Minerals Acquisition”) in a cash transaction valued at approximately $17.0 million,, subject to customary post-closing adjustments. The Permian Minerals Acquisition has an effective date of MayAugust 1, 2025.2026. We funded the purchase price for the Permian Minerals Acquisition with a combination of $15.0net proceeds from our concurrent public equity offering and $3.2 million in borrowings under our Senior Secured Credit Facility and cash on hand.Facility. The acquired assets include an average royalty interest of 0.6% located on approximately 5,5003,420 net royalty acres locatedacross primarilyReagan, inMartin, GradyMidland, Glasscock, and CanadianUpton Counties, Oklahoma.Texas.

On October 21, 2024, we entered into an ATM equity Sales Agreement (the “ATM Sales Agreement”) with Roth Capital Partners, LLC (the “Lead Agent”), Northland Securities Inc., and A.G.P./Alliance Global Partners pursuant to which we may issue and sell, from time to time, up to $30.0 million of shares of common stock through or to the Lead Agent, acting as agent or principal.principal to facilitate acquisitions and other general corporate purposes. On February 11, 2026, the Company executed a new ATM equity Sales Agreement, substantially consistent with the original October 2024 agreement (the “ATM Sales Agreements”) restoring the $30.0 million common stock sales capacity. For the year ended June 30, 2025,2026, we sold a total of approximately 0.71.4 million shares of our common stock under the ATM Sales AgreementAgreements for net proceeds of approximately $3.5$5.8 million, afternet deductingof $0.3$0.2 million inof offering costs.costs Weincurred. intend to use the netNet proceeds from anythe sales of common stock were used to fund a portion of our Louisiana Minerals acquisitions and for general corporate purposes, including to repay outstanding indebtedness.

Proved oil equivalent reserves as of June 30, 20252026 were 27.127.2 MMBOE, a 4.70.1 MMBOE, or 14.8%,0.4%, decreaseincrease from the previous year of 31.827.1 MMBOE. The net decreaseincrease in total proved reserves was primarily due to net negative revisions of 6.0 MMBOE and production roll-off of 2.6 MMBOE. These decreases were partially offset by 3.01.6 MMBOE of proved reserves purchased infrom theour TexMexSCOOP/STACK Minerals Acquisition and Louisiana Minerals acquisitions as well as extensions of 0.90.4 MMBOE primarily at Chaveroo FieldSCOOP/STACK and SCOOP/STACK.net positive revisions of 0.7 MMBOE partially offset by production roll off of 2.6 MMBOE. Approximately 1.62.2 MMBOE of downward revisions were in our oil reserves and 4.4 MMBOE of downwardupward revisions were in our natural gas reserves were partially offset by approximately 1.4 MMBOE of downward revisions in our oil and NGL reserves. ProvedNatural oilgas reserves declinedincreased primarily due to aan decreaseincrease in the SEC trailing 12-month oilnatural gas price of 10.4%26.1% from the prior fiscal yearyear. and drop-off of Williston Basin PUDs due to timing of future drilling plans. Natural gasOil and natural gas liquids reservesdownward decreasedrevisions were a result of a reduction in the economic life of certain oil fields due to aincreased combination of lower price differentials received, specifically at Jonah Field, an increase in lease operating costs at our Barnett Shale properties, and drop-off of the Williston Basin PUDs due to timing of future drilling plans. These metrics impacted the late-in-life economic limits for oil, natural gas, and NGL production.costs.

The oil and natural gas industry is a global market impacted by many factors, such as government regulations, particularly in the areas of tariffs, trade sanctions, taxation, energy, climate change and the environment, geopolitical instability and armed conflictsinstability, (including ongoing conflicts between Russia and Ukraine andUkraine, in the Middle East between Israel and GazaVenezuela), demand in Asian and European markets, and the extent to which members of OPEC and other oil exporting nations manage oil supply through export quotas. More recently, during the third fiscal quarter, WTI oil prices reached their highest levels since 2022 due to crude oil disruptions at key oil shipping routes in the Middle East, including the Strait of Hormuz. Natural gas prices are generally determined by North American supply and demand and are also affected by imports and exports of liquefied natural gas. Weather also has a significant impact on demand for natural gas since it is a primary heating source.

Oil, natural gas, and NGL prices have been, and we expect may continue to be, volatile. During the current fiscal year, crude oil spot prices for WTI dropped below $56 per barrel in December 2025 then rose to more than $100 per barrel in March 2026. Lower oil and natural gas prices not only decrease our revenues, partially offset by applicable hedges, but an extended decline in oil or natural gas prices may affect planned capital expenditures and the oil and natural gas reserves that we can economically produce. Lower oil and natural gas prices may also reduce the amount of our borrowing base under our Senior Secured Credit Facility, which is determined at the discretion of the lenders based on various factors including the collateral value of our proved reserves. Increases in crude oil and natural gas prices are partially offset to the extent that prices exceed applicable derivative contract swap and collar prices.

Given the dynamic nature of these factors and events, we cannot reasonably estimate the period of time that certain market conditions will persist. Continuing volatility in political, trade, regulatory and economic conditions could impact supply and demand fundamentals,fundamentals andas anywell as commodity pricing. Any related significant declines in crude oil, natural gas, and NGL prices could lead to proved property impairments in the future. FutureAny impairmentssignificant increases in commodity prices could lead to further losses on our derivative contacts that partially offset price increases. Impairments of proved properties and gains and losses on derivative contracts are difficult to predict, especially in a volatile price environment.

As of June 30, 2025,2026, we had $6.1 million in cash and cash equivalents and $56.5 million outstanding borrowings on our Senior Secured Credit Facility compared to $2.5 million in cash and cash equivalents and $37.5 million outstanding borrowings on our Senior Secured Credit Facility compared to $6.4 million in cash and cash equivalents and $39.5 million outstanding borrowings on our Senior Secured Credit Facility at June 30, 2024.2025. Our primary sources of liquidity and capital resources during the year ended June 30, 20252026 were cash provided by operationsoperations, net borrowings under our Senior Secured Credit Facility, and net proceeds from the ATM Sales agreement.Agreements. Our primary uses of liquidity and capital resources for the year ended June 30, 20252026 were cash used to fund our SCOOOP/STACK Minerals Acquisition and Louisiana Minerals, cash dividend payments to our common stockholders, our TexMex Acquisition, net repayments of borrowings under our Senior Secured Credit Facility and development capital expenditures,expenditures. As of June 30, 2026, working capital was a deficit of $1.8 million, primarily due to our current derivative contracts, which vary quarter-to-quarter based on forecasted commodity prices at Chaveroothe Fieldend andof SCOOP/STACK.each quarter. As of June 30, 2025, working capital was a deficit of $4.0 million. As of June 30, 2024, working capital was $5.9 million.

As noted above, on June 30, 2025, we entered into aThe syndicated amended and restated senior secured reserve-based credit agreement (the “Senior Secured Credit Facility”) with MidFirst Bank, as administrative agent for the lenders party thereto. The Senior Secured Credit Facility has a maximum capacity of $200.0 million subject to a borrowing base determined by the lenders based on a percentage of the value of our oil and natural gas properties. TheAs of June 30, 2026, the Senior Secured Credit Facility hashad a current borrowing base of $65.0 million. As of June 30, 2025,2026, we had $37.5$56.5 million of indebtednessindebtedness, $0.8 million of letters of credit outstanding and availabilityavailable capacity of $27.5$7.7 million. The Senior Secured Credit Facility is secured by substantially all of our oil and natural gas properties and matures on June 30, 2028.

Borrowings bear interest, at our option, at either (i) the SOFR, subject to a minimum SOFR of 3.25%, plus a credit spread adjustment of 0.05%, or (ii) the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%, plus, in either case of (i) or (ii), an applicable margin of 2.75%. For the years ended June 30, 20252026 and 2024,2025, the weighted average interest on our borrowings were 7.48%6.69% and 8.12%,7.48%, respectively. The Senior Secured Credit Facility contains covenants requiring the maintenance of (i) a 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. In addition, the Senior Secured Credit Facility contains hedging requirements that apply when utilization is greater than 25% of (x) the Margined Collateral Value, as defined under the Senior Secured Credit Facility, at any time when the leverage ratio is less than 2.25 to 1.00, or (y) the borrowing base, at any time when the leverage ratio is greater than or equal to 2.25 to 1.00. It also contains other customary affirmative and negative covenants, including a hedging covenant discussed below, and events of default. As of June 30, 2025,2026, we were in compliance with all covenants under the Senior Secured Credit Facility.

The Senior Secured Credit Facility requires for redeterminations of the borrowing base to occur semi-annually. At each redetermination, the Margined Collateral Value is updated based on the estimated value of our oil and natural gas properties, which includes our proved developed reserves, proved undeveloped reserves, and other relevant factors consistent with customary oil and natural gas lending criteria. On November 28, 2025, we entered into a letter agreement with MidFirst Bank pursuant to which the Margined Collateral Value, as defined under the Senior Secured Credit Facility, was modified to $65.0 million. In addition, it granted us additional time to enter into further commodity hedges to meet the hedging requirements under the Senior Secured Credit Facility. On August 29, 2025, we entered into anthe first amendment to our Senior Secured Credit Facility with MidFirst Bank, whereas it was determined for purposes of the hedge covenant that total crude oil and natural gas production volumes from proved developed producing reserves will be combined on a barrels of oil equivalent (“BOE”) basis to determine compliance with the hedging covenant.

On October 21, 2024, we entered into an ATM equity Sales Agreement with Roth Capital Partners, LLC as our Lead Agent, Northland Securities Inc., and A.G.P./Alliance Global Partners pursuant to which we may issue and sell, from time to time, up to $30.0 million of shares of common stock through or to the Lead Agent, acting as agent or principal.principal to facilitate acquisitions and other general corporate purposes. On February 11, 2026, we executed a new ATM equity Sales Agreement, substantially consistent with the original October agreement restoring the $30.0 million common stock sales capacity. For the year ended June 30, 2025,2026, we sold a total of approximately 0.71.4 million shares of our common stock under the ATM Sales AgreementAgreements for net proceeds of approximately $3.5$5.8 million, afternet deductingof $0.3$0.2 million inof offering costs.costs incurred.

Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 4751 consecutive quarterly dividends. Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of our financial strategy, and it is our long-term goal to maintain or increase dividends over time, subject to adjustments as appropriate.appropriate in the Board of Directors’ discretion depending on factors such as commodity prices, other opportunities for uses of capital, and any other factors the Board of Directors deems relevant. On September 11,10, 2025,2026, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on September 22,21, 20252026 and payable on September 30, 2025.2026.

Based on discussions with our operators, we expect capital workover projects to continue in most of our fields.fields as well as further drilling at SCOOP/STACK. Overall, for fiscal year 2026,2027, we expect budgeted capital expenditures to be in the range of $4.0 million to $6.0 million, which excludes the recent purchase of Permian Minerals, any other potential acquisitions.acquisitions, and drilling at Chaveroo Field. Our expected capital expenditures for the next 12 months include bringing approximately fiveten gross wells online at our SCOOP/STACK properties.STACK. Additionally, as our third-party operators continue to be active around our acreage, we would expect additional wells to be drilled and/or completed. At Chaveroo Field, we expect to have drilling permits in hand for the next round of six wells before the end of the fiscal third quarter 2026 and the final decision by us and our partner as to timing for spudding these wells will be made based on oil prices and completed well costs at that time.

Funding for our anticipated capital expenditures over the near-term is expected to be met from cash flows from operationsoperations, net proceeds from our ATM Sales Agreements, and as needed from borrowings under our Senior Secured Credit Facility.

Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated depletion, depreciation, and amortization and related deferred taxes, are limited to the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and natural gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average first day of the month price for our petroleum products during the 12-month period ending with the balance sheet date. The prices used in calculating our ceiling test as of June 30, 20252026 were $71.20$72.93 per barrel of oil, $2.87$3.62 per MMBtu of natural gas and $25.24$27.50 per barrel of NGLs. As of June 30, 2025,2026, our capitalized costs of oil and natural gas propertiesproperties, subject to amortization, were below the full cost valuation ceiling. If commodity price levels were to substantially decline from the 12-month average first day of the month pricing levels as of June 30, 20252026 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 quarters.quarters and the effect could be material to our net earnings. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties to our full cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required at some point in the future.future Additionally, a 10% reduction in respectiveas commodity prices atare Junevolatile 30,and 2025,unpredictable. whileUsing first day of the month prices for July, August and September 2026, which are more reflective of recent prices trends, to calculate a trailing 12-month average price of $76.56 per barrel of oil and $3.60 per MMBtu of natural gas, and keeping all other factors remainedconstant, constant,the ceiling test calculation as of the fourth quarter of fiscal year 2026 would not have generated ana ceiling test impairment.

Net cash flows usedprovided inby financing activities for the year ended June 30, 20252026 were $15.3$7.3 million compared to net cash flows providedused byin financing activities of $22.3$15.3 million for the year ended June 30, 2024.2025. In the current year period, we received net borrowings of $19.0 million under our Senior Secured Credit Facility primarily to finance our SCOOP/STACK Minerals Acquisition, received net proceeds from the sale of common stock under the ATM Sales Agreements of approximately $5.8 million, after deducting $0.2 million of issuance fees paid, and paid $16.9 million in cash dividends to our common stockholders. In the prior year period, we paid $16.3 million in cash dividends to our common stockholders, repaid $2.0 million of net borrowings under our Senior Secured Credit Facility, and received net proceeds from the sale of common stock under the ATM Sales Agreement of approximately $3.5 million, after deducting $0.3 million in offering costs. In the prior year period, we received net borrowings of $39.5 million under our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions, paid $16.0 million in cash dividends to our common stockholders together with $0.8 million paid to repurchase shares of common stock under our share repurchase plan.

We reported a net loss of $2.4 million and net income of $1.5 million and $4.1 million for the years ended June 30, 20252026 and 2024,2025, respectively. The following table summarizes the comparison of financial information for the periods presented:

Crude oil, natural gas and NGL revenues were $85.8$86.3 million and $85.9$85.8 million for the fiscal years ended June 30, 20252026 and 2024,2025, respectively. The decreaseincrease in revenues is primarily due to the decreaseincrease in our average realized price per BOE partially offset by an increase in our sales volumes primarily as a result of our recent acquisitions.BOE. Our average realized commodity price (excluding the impact of derivative contracts) decreasedincreased approximately $1.31$0.18 per BOE, or 3.8%,0.5%, for the fiscal year ended June 30, 20252026 compared to June 30, 2024.2025. 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.factors, such as geopolitics. While our average realized natural gas prices increased 6.1% from the prior fiscal year, our average realized crude oil and NGL prices decreased 11.5%0.1% and 0.1%5.4% from the prior fiscal year respectively,respectively. ourThe averagecurrent realizedyear commodityoil prices,revenue realizedat naturalDelhi gasField priceswas increasedalso 7.3%impacted fromby the$1.2 million of prior fiscalperiod yearadjustments predominatelyfor transportation charges due to favorablea pricingnew recognizedmarketing fromcontract ourentered SCOOP/STACKinto properties.by the operator dating back to December 2024. Average daily equivalent production increased 4.2%slightly from 6,7907,074 BOEPD to 7,0747,077 BOEPD in the current fiscal year as a result of additional production from newlyour drilledSCOOP/STACK wellsMinerals atAcquisition Chaverooin Field,August the2025 Texand MexTexMex Acquisition in April 2025,2025 and drillingnewly activitiesdrilled that are ongoingwells at SCOOP/STACK since the prior year end. The increase in production was partially offset by natural production declines in our other fields.

Ad valorem and production taxes were $5.7$4.8 million and $5.3$5.7 million for the years ended June 30, 20252026 and 2024,2025, respectively. The increasedecrease is primarily related to an $0.8 million reduction of calendar years 2024 and 2025 ad valorem taxes which were passed along from the operator of our Barnett Shale natural gas properties in fiscal year 2026. The decrease in ad valorem and production taxes iswas primarilypartially dueoffset toby our SCOOP/STACK AcquisitionsMinerals sinceAcquisition thein priorAugust year2025 period.and our TexMex Acquisition in April 2025. On a per unit basis, ad valorem and production taxes were $2.21$1.84 per BOE and $2.13$2.21 per BOE for the years ended June 30, 20252026 and 2024,2025, respectively.

Gathering, transportation and other costs were $11.1 million for the year ended June 30, 2026 compared to $11.4 million for the year ended June 30, 2025 compared to $9.7 million for the year ended June 30, 2024.2025. These costs are gathering, transportation and processing fees we incur primarily for our natural gas producing properties. The increasedecrease is primarily due to the SCOOP/STACK Acquisitionsdecrease in Februarynatural 2024gas whichsales increasedat gathering,Jonah transportation and other costs by $1.2 million over the prior year period.Field. On a per unit basis, gathering, transportation and other costs were $4.40$4.31 per BOE and $3.89$4.40 per BOE for the years ended June 30, 20252026 and 2024,2025, respectively.

Depletion expense increased $1.8$0.8 million or 9.5%4.0% from $18.6 million for the fiscal year ended June 30, 2024 to $20.4 million for the fiscal year ended June 30, 2025 to $21.2 million for the fiscal year ended June 30, 2026 primarily due to an increase in the depletion rate. On a per unit basis, depletion expense was $7.89$8.21 per BOE and $7.49$7.89 per BOE for the fiscal years ended June 30, 20252026 and 2024,2025, respectively. The depletion rate of our unit of production calculation increased primarily due to an overall decreaseincrease in our reservesdepreciable estimatesbase due to acquisitions since the prior year period.

General and administrative expenses for the fiscal year ended June 30, 20252026 increaseddecreased $0.4$0.5 million, or 4.7%,5.7%, to $7.9$7.4 million compared to $7.5$7.9 million for the fiscal year ended June 30, 2024.2025. The increasedecrease primarily relates higher salary andreduced compensation expense adjustmentsin forthe existingcurrent employees.year. On a per unit basis, general and administrative expenses were $3.04$2.87 per BOE and $3.02$3.04 per BOE for the years ended June 30, 20252026 and 2024,2025, respectively.

Stock-based compensation increased $0.3 milliondecreased to $2.5$2.3 million for the year ended June 30, 20252026 comparedfrom to $2.1$2.5 million the prior period. The increasedecrease is due to newa reduction in the awards granted duringin the current fiscal year compared to the prior fiscal year.

We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. Financial hedges are a requirement under our Senior Secured Credit Facility and help establish commodity price floors, contributing to stable cash flows when derivative contracts are settled. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the consolidated statements of operations. The amounts recorded on the consolidated statements of operations related to derivative contracts represent the (i) gains (losses) related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) gains (losses) on settlements of derivative contracts for positions that have settled or been realized. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized (gains) losses on our average realized prices for the periods presented. As a result of our SCOOP/STACK AcquisitionsMinerals Acquisition in FebruaryAugust 20242025, and the corresponding borrowings on our Senior Secured Credit Facility, we were required by terms in our Senior Secured Credit Facility to hedge a portion75% of our production.crude Theoil increaseand natural gas production (excluding NGLs). Subsequently, in March 2026,WTI oil prices reached their highest levels since 2022 due to crude oil disruptions at key oil shipping routes in the Middle East, contributing to considerable commodity price fluctuations and realized losses on our crude oil derivative contracts. Whereas, the decrease in forward curvecommodity prices for future natural gas prices,gas, as of June 30, 2025 as compared to June 30, 2024,2026, resulted in a netan unrealized lossgain on the mark-to-market of our hedges for the year ended June 30, 2025.hedges. As of June 30, 2025,2026, we had a $2.0$2.6 million derivative asset, $1.8$2.1 million of which was classified as current, and a $3.4$3.1 million derivative liability, $1.6$2.9 million of which was classified as current. We expect to see continued volatility in the fair value of our derivative contracts as commodity prices fluctuate.

“Current quarter” refers to the three months ended DecemberMarch 31, 2025,2026, our secondthird quarter of fiscal year 2026.

“Year-ago quarter” refers to the three months ended DecemberMarch 31, 2024,2025, our secondthird quarter of fiscal year 2025.

Our oil and natural gas properties consist primarily of non-operated working and mineral interests in the following areas (as well as small overriding royalty and mineral interests in four onshore central Texas wellsand Louisiana):

On FebruaryMay 9,11, 2026, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable MarchJune 31,30, 2026.

On November 28, 2025, we entered into a letter agreement with MidFirst Bank pursuant to which the Margined Collateral Value, as defined under the Senior Secured Credit,Credit Facility, was modified to $65.0 millionmillion. andIn allowedaddition, it granted us untiladditional December 31, 2025time to enter into additionalfurther commodity hedge transactionshedges to satisfymeet the level of hedging requirements.requirements under the Senior Secured Credit Facility.

Purchase of SCOOP/STACK Minerals Transactions

On August 4, 2025, we completed the acquisition of certain mineral and royalty interests in the SCOOP and STACK plays in Oklahoma from a non-affiliated private seller (the “SCOOP/STACK Minerals Acquisition”) in a cash transaction valued at approximately $16.3 million, which includes $17.0 million paid at closing less transaction costs of $0.1 million and interim purchase price adjustments totaling approximately $0.7$0.8 million related to net cash flows earned on the properties from the effective date to the closing date. We expect to receive the remaining net cash flows from the properties between the effective date of May 1, 2025 andto the closing date, at the final post-closing settlement process expected to occur during the third quarter of fiscal 2026.date. We accounted for the transaction as an asset acquisition and the allocation of the purchase price was $11.7$12.5 million to proved oil and natural gas properties, subject to amortization, and $4.6$3.8 million to unproved properties. We funded the purchase price for the SCOOP/STACK Minerals Acquisition with a combination of $15.0 million in borrowings under our Senior Secured Credit Facility and cash on hand. The acquired assets include an average royalty interest of 0.6% across approximately 5,500 net royalty acres located primarily in Grady and Canadian Counties, Oklahoma.

The oil and natural gas industry is a global market impacted by many factors, such as government regulations, particularly in the areas of tariffs, trade sanctions, taxation, energy, climate change and the environment, geopolitical instability, (including ongoing conflicts between Russia and Ukraine, in the Middle East and Venezuela), demand in Asian and European markets, and the extent to which members of OPEC and other oil exporting nations manage oil supply through export quotas. More recently, during the third fiscal quarter, WTI oil prices reached their highest levels since 2022 due to crude oil disruptions at key oil shipping routes in the Middle East, including the Strait of Hormuz. Natural gas prices are generally determined by North American supply and demand and are also affected by imports and exports of liquefied natural gas. Weather also has a significant impact on demand for natural gas since it is a primary heating source.

Oil, natural gas, and NGL prices have been, and we expect may continue to be, volatile. During the current fiscal year, crude oil spot prices for WTI dropped below $56 per barrel in December 2025 then rose to more than $100 per barrel in March 2026. Lower oil and natural gas prices not only decrease our revenues, partially offset by applicable hedges, but an extended decline in oil or natural gas prices may affect planned capital expenditures and the oil and natural gas reserves that we can economically produce. Lower oil and natural gas prices may also reduce the amount of our borrowing base under our Senior Secured Credit Facility, which is determined at the discretion of the lenders based on various factors including the collateral value of our proved reserves. Increases in crude oil and natural gas prices are partially offset to the extent that prices exceed applicable derivative contract swap and collar prices.

Given the dynamic nature of these factors and events, we cannot reasonably estimate the period of time that certain market conditions will persist. Continuing volatility in political, trade, regulatory and economic conditions could impact supply and demand fundamentals,fundamentals andas anywell as commodity pricing. Any related significant declines in crude oil, natural gas, and NGL prices could lead to proved property impairments in the future. FutureAny impairmentssignificant ofincreases provedin propertiescommodity prices could lead to further losses on our derivative contacts that partially offset price increases. Impairments and gains and losses on derivative contracts are difficult to predict, especially in a volatile price environment.

As of DecemberMarch 31, 2025,2026, we had $3.8$2.6 million in cash and cash equivalents and $54.5$56.5 million outstanding borrowings on our Senior Secured Credit Facility compared to $2.5 million in cash and cash equivalents and $37.5 million outstanding borrowings on our Senior Secured Credit Facility at June 30, 2025. Our primary sources of liquidity and capital resources during the sixnine months ended DecemberMarch 31, 20252026 were cash provided by operations andoperations, net borrowings under our Senior Secured Credit Facility.Facility, and net proceeds from the ATM Sales Agreements. Our primary uses of liquidity and capital resources for the sixnine months ended DecemberMarch 31, 20252026 were cash used to fund our SCOOP/STACK Minerals Acquisition,Acquisition and Louisiana Minerals, cash dividend payments to our common stockholders, and development capital expenditures. As of DecemberMarch 31, 2025,2026, working capital was a deficit of $2.0$10.6 million.million primarily due to our current derivative contracts, which vary quarter-to-quarter based on forecasted commodity prices at the end of each quarter. As of June 30, 2025, working capital was a deficit of $4.0 million.

The syndicated Senior Secured Credit Facility has a maximum capacity of $200.0 million subject to a borrowing base determined by the lenders based on a percentage of the value of our oil and natural gas properties. The Senior Secured Credit Facility has a current borrowing base of $65.0 million. As of DecemberMarch 31, 2025,2026, we had $54.5$56.5 million of indebtedness, $0.8 million of letters of credit outstanding, and available capacity of $9.7$7.7 million. The Senior Secured Credit Facility is secured by substantially all of our oil and natural gas properties and matures on June 30, 2028.

For the sixnine months ended DecemberMarch 31, 20252026 and 2024,2025, the weighted average interest on our borrowings was 6.88%6.78% and 7.80%,7.59%, respectively. Borrowings bear interest, at our option, at either (i) the SOFR, subject to a minimum SOFR of 3.25%, plus a credit spread adjustment of 0.05%, or (ii) the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%, plus, in either case of (i) or (ii), an applicable margin of 2.75%. The Senior Secured Credit Facility contains covenants requiring the maintenance of (i) a 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. In addition, the Senior Secured Credit Facility contains hedging requirements that apply when utilization is greater than 25% of (x) the Margined Collateral Value, as defined under the Senior Secured Credit Facility, at any time when the leverage ratio is less than 2.25 to 1.00, or (y) the borrowing base, at any time when the leverage ratio is greater than or equal to 2.25 to 1.00. It also contains other customary affirmative and negative covenants, including a hedging covenant discussed below, and events of default. As of DecemberMarch 31, 2025,2026, we were in compliance with all covenants under the Senior Secured Credit Facility.

The Senior Secured Credit Facility requires redeterminations of the borrowing base to occur semi-annually. At each redetermination, the Margined Collateral Value is updated based on the estimated value of our oil and natural gas properties, which includes our proved developed reserves, proved undeveloped reserves, and other relevant factors consistent with customary oil and natural gas lending criteria. On November 28, 2025, we entered into a letter agreement with MidFirst Bank pursuant to which the Margined Collateral Value, as defined under the Senior Secured Credit,Credit Facility, was modified to $65.0 millionmillion. andIn allowedaddition, it granted us untiladditional December 31, 2025time to enter into additionalfurther commodity hedge transactionshedges to satisfymeet the level of hedging requirements.requirements under the Senior Secured Credit Facility. On August 29, 2025, we entered into the first amendment to our Senior Secured Credit Facility with MidFirst Bank, whereas it was determined for purposes of the hedge covenant that total crude oil and natural gas production volumes from proved developed producing reserves will be combined on a barrels of oil equivalent (“BOE”) basis to determine compliance with the hedging covenant.

We have historically funded operations through cash from operations and working capital. Our primary source of cash is the sale of produced crude oil, natural gas, and NGLs. A portion of these cash flows is used to fund capital expenditures and pay cash dividends to shareholders. We expect to fund near-future capital development activities for our properties with cash flows from operating activities, and, as needed, borrowings under our Senior Secured Credit Facility and proceeds from the ATM Sales Agreement.Agreements.

We are pursuing new growth opportunities through acquisitions and other transactions. In addition to cash on hand, we have access to the undrawn portion of the borrowing base available under our Senior Secured Credit Facility, totaling $9.7$7.7 million as of DecemberMarch 31, 2025.2026. We also have an effective shelf registration statement with the SEC under which we may issue up to $500.0 million of new debt or equity securities.

On October 21, 2024, we entered into an ATM equity Sales Agreement with Roth Capital Partners, LLC as our Lead Agent, Northland Securities Inc., and A.G.P./Alliance Global Partners pursuant to which we may issue and sell, from time to time, up to $30.0 million of shares of common stock through or to the Lead Agent, acting as agent or principal to facilitate acquisitions and other general corporate purposes. On February 11, 2026, we executed a new ATM equity Sales Agreement, substantially consistent with the original October agreement restoring the $30.0 million common stock sales capacity. During the sixnine months ended DecemberMarch 31, 2025,2026, we sold a total of approximately 0.31.1 million shares of our common stock under the ATM Sales AgreementAgreements for net proceeds of approximately $1.2$4.7 million, net of $46$0.2 thousandmillion of offering costs.costs incurred.

Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 4950 consecutive quarterly dividends. Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of our financial strategy, and it is our long-term goal to increase dividends over time, subject to adjustments as appropriate in the Board of Directors’ discretion depending on factors such as commodity prices, other opportunities for uses of capital, and any other factors the Board of Directors deems relevant. On FebruaryMay 9,11, 2026, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on MarchJune 16,15, 2026 and payable on MarchJune 31,30, 2026.

During the sixnine months ending DecemberMarch 31, 2025,2026, we incurred $2.5$4.0 million on development capital expenditures. A majority of our spending occurred at SCOOP/STACK, Chaveroo Field and Hamilton Dome Field. At SCOOP/STACK where our operators are actively drilling. Threeeight gross wells were brought online during the firstnine quartermonths ofended theMarch year,31, and2016, three gross wells are currently in progress.progress, and we have elected to participate in two gross wells. At Chaveroo Field and Hamilton Dome capital spending projects were for facility upgrades and consolidations. Remaining capital spending related to capital workover projects across our portfolio of assets. Based on discussions with our operators, we expect capital workover projects to continue in most of our fields throughout the remainder of the year as well as further drilling at SCOOP/STACK.

Overall, for fiscal year 2026, we expect budgeted capital expenditures to be in the range of $4.0 million to $6.0 million, which excludes the purchase of Louisiana Minerals described above, as well as any other potential acquisitions. Our expected capital expenditures for fiscal year 2026 include bringing approximately nineeleven gross wells online, including the sixeight gross wells described above, at our SCOOP/STACK properties. Additionally, as our third-party operators continue to be active around our acreage, we would expect additional wells to be drilled and/or completed. At Chaveroo Field, we anticipate securing permits for the next six wells before the end of the fiscal year 2026. The final decision, made jointly with our partner, on when to spud these wells will depend on prevailing oil prices and completed well costs at that time.

Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated depletion, depreciation, and amortization and related deferred taxes, are limited to the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and natural gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average first day of the month price for our petroleum products during the 12-month period ending with the balance sheet date. The prices used in calculating our ceiling test as of DecemberMarch 31, 20252026 were $66.01$63.80 per barrel of oil, $3.40$3.72 per MMBtu of natural gas and $23.22$22.50 per barrel of NGLs. As of DecemberMarch 31, 2025,2026, our capitalized costs of oil and natural gas properties, subject to amortization, were below the full cost valuation ceiling. If commodity price levels were to substantially decline from the 12-month average first day of the month pricing levels as of DecemberMarch 31, 20252026 and remain down for a prolonged period of time, our valuation ceiling over our capitalized costs may be reduced and adversely impact our ceiling test results in future quarters and the effect could be material to our net earnings. Using first day of the month prices for JanuaryApril and FebruaryMay 2026, which are more reflective of recent prices trends, to calculate a trailing 12-month average price of $64.05$70.06 per barrel of oil and $3.80$3.58 per MMBtu of natural gas, and keeping all other factors constant, the ceiling test calculation as of the secondfourth quarter of fiscal year 2026 would not have generated a ceiling test impairment. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required at some point in the future as commodity prices are volatile and unpredictable. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties to our full cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Cash provided by operating activities for the sixnine months ended DecemberMarch 31, 20252026 decreased $2.1$5.9 million compared to the sixnine months ended DecemberMarch 31, 20242025 primarily due a decrease in revenues of $2.6 million from the prior period and increases in our interest expense and lease operating costs for the comparable periods partially offset by realized gainslosses on derivative contractscontracts. Interest expense increased $0.6 million and in the current period we had net derivative realized losses of $1.7$0.6 million compared to $0.1realized gains $0.2 million in the prior period. The remaining decrease in cash flow from operations is due to timing of working capital. Refer to “Results of Operations” below for further information.

Cash used in investing activities for the sixnine months ended DecemberMarch 31, 20252026 increased $17.5$17.2 million compared to the sixnine months ended DecemberMarch 31, 20242025 primarily due to the closing of the SCOOP/STACK Minerals Acquisition in August 2025.2025 and Louisiana Minerals from December 2025 through March 2026.

Net cash flows provided by financing activities for the sixnine months ended DecemberMarch 31, 20252026 were $9.3$10.6 million compared to net cash flows used in financing activities of $6.3$13.4 million for the sixnine months ended DecemberMarch 31, 2024.2025. For the sixnine months ended DecemberMarch 31, 2025,2026, we received net borrowings of $17.0$19.0 million under our Senior Secured Credit Facility primarily to finance our SCOOP/STACK Minerals Acquisition, received net proceeds from the sale of common stock under the ATM Sales agreementAgreements of approximately $1.2$4.8 million, after deducting $0.1 million of issuance fees,fees paid, and paid $8.4$12.6 million in cash dividends to our common stockholders. For the sixnine months ended DecemberMarch 31, 2024,2025, we paid $8.1$12.2 million in cash dividends to our common stockholdersstockholders, repaid $4.0 million of borrowings under our Senior Secured Credit Facility, and received net proceeds from the sale of common stock under the ATM Sales AgreementAgreements of approximately $2.0$3.1 million, after deducting $0.2$0.3 million of fees for due diligence incurred with the offering.

Three Months Ended DecemberMarch 31, 20252026 and 20242025

We reported net incomelosses of $1.1$8.9 million and net loss of $1.8$2.2 million for the three months ended DecemberMarch 31, 20252026 and 2024,2025, respectively. The following table summarizes the comparison of financial information for the periods presented:

Ad valorem and production taxes were $0.6$1.3 million and $1.4$1.5 million, respectively, for the three months ended DecemberMarch 31, 20252026 and 2024.2025. The $0.8 million decrease is directlyprimarily relateddue to alower reductioncommodity ofprices calendar years 2024 and 2025 ad valorem taxes which were passed along from the operator of our Barnett Shale natural gas properties.received. On a per unit basis, ad valorem and production taxes were $0.87$2.18 per BOE and $2.26$2.46 per BOE for the three months ended DecemberMarch 31, 20252026 and 2024,2025, respectively.

Gathering, transportation and other costs were $2.7$2.8 million for the three months ended DecemberMarch 31, 20252026 compared to $2.9 million for the three months ended DecemberMarch 31, 2024.2025. These costs are gathering, transportation and processing fees we incur primarily for our natural gas producing properties. The decrease is primarily due to decreased natural gas sales at Jonah Field and Barnett Shale. On a per unit basis, gathering, transportation and other costs were $3.93$4.70 per BOE and $4.53$4.86 per BOE for the three months ended DecemberMarch 31, 20252026 and 2024,2025, respectively.

Other lease operating costs were $8.3$8.8 million for the three months ended DecemberMarch 31, 20252026 compared to $8.5$9.0 million for the three months ended DecemberMarch 31, 2024.2025. Other lease operating costs decreased primarily due to the cessation of CO2 purchases at Delhi late during the third quarter of fiscal 2025. For the three months ended DecemberMarch 31, 2024,2025, we had net CO2 purchases of $1.1$1.5 million. Partially offsetting the overall decrease in other lease operating costs were increases due to the TexMex Acquisition in April 2025,2025. which increased other lease operating costs by $1.1 million overDuring the priorcurrent yearquarter, period.the operator at TexMex focused on workover projects and facilities upgrades in the field. On a per unit basis, other lease operating costs decreased to $12.16$14.61 per BOE for the three months ended DecemberMarch 31, 20252026 from $13.26$15.00 per BOE in the three months ended DecemberMarch 31, 2024.2025.

Depletion expense increased from $5.0$4.6 million for the three months ended DecemberMarch 31, 20242025 to $5.5$4.9 million for the three months ended DecemberMarch 31, 20252026 primarily due to an increase in the depletion rate and decrease in reserves volumes. On a per unit basis, depletion expense was $8.15$8.13 per BOE and $7.87$7.68 per BOE for the three months ended DecemberMarch 31, 20252026 and 2024,2025, respectively.

General and administrative expenses were $2.0$1.9 million for each of the periodsthree months ended DecemberMarch 31, 20252026 and 2024.2025. On a per unit basis, general and administrative expenses were $2.91$3.11 per BOE and $3.13$3.22 per BOE for the three months ended DecemberMarch 31, 20252026 and 2024,2025, respectively. The decrease on a per unit basis is primarily the result of the increase in production for the current year period.

Stock-based compensation expense for the threenine months ended DecemberMarch 31, 20252026 was $0.6$1.7 million compared to $0.7$1.9 million for the year-ago period. The decrease is due to athe decreasevesting inof thesign-on awards granted in theprior current fiscal period compared to the year-ago period.years.

We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. Financial hedges are a requirement under our Senior Secured Credit Facility and help establish commodity price floors, contributing to stable cash flows when derivative contracts are settled. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the unaudited condensed consolidated statements of operations. The amounts recorded on the unaudited condensed consolidated statements of operations related to derivative contracts represent the (i) gains (losses) related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) gains (losses) on settlements of derivative contracts for positions that have settled or been realized. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized gains (losses) on our average realized prices for the periods presented. As a result of our recent acquisitions and the corresponding borrowings on our Senior Secured Credit Facility, we were required by terms in our Senior Secured Credit Facility to hedge a portion of our production. During the fiscal third quarter, WTI oil prices reached their highest levels since 2022 due to crude oil disruptions at key oil shipping routes in the Middle East, contributing to commodity price volatility. The significant increase in forward commodity prices as of March 31, 2026, resulted in an unrealized loss on the mark-to-market of our hedges. As of DecemberMarch 31, 2025,2026, we had $3.3$3.1 million derivative assets, $3.2$2.4 million of which was classified as current, and $2.0$9.3 million derivative liabilities, $1.5$8.5 million of which was classified as current. Subsequent to the end of the quarter through February 2026, we have seen increased volatility in the crude oil and natural gas commodity markets, and weWe expect to see continued volatility in the fair value of our derivative contracts.contracts as commodity prices fluctuate.

Interest expense increased $0.2$0.6 million for the threenine months ended DecemberMarch 31, 20252026 compared to the prior year period primarily due to additional borrowings drawn on our Senior Secured Credit Facility to finance our SCOOP/STACK Minerals Acquisition in August 2025. The weighted average interest rate on our borrowings was 6.78% for the nine months ended March 31, 2026 compared to 7.59% for the nine months ended March 31, 2025.

For the threenine months ended DecemberMarch 31, 2025,2026, we recognized income tax expensebenefit of $0.8$1.2 million on net incomelosses before income taxes of $1.9$8.3 million compared to income tax benefit of $0.7$0.6 million on net losses before income taxes of $2.5 million for the threenine months ended DecemberMarch 31, 2024.2025. The effective tax rates were 44.0%14.9% and 28.0%22.9% for threenine months ended DecemberMarch 31, 20252026 and 2024,2025, respectively. The increase in the effective tax rate from the prior year period is due to projected higher state income taxes in Oklahoma associated with the Minerals Acquisition in August 2025. We continue to evaluate our tax provision on a quarterly basis and adjust our effective tax rate for any given changes in facts and circumstances that are expected in the future.