Executive Overview Liquidity and Capital Resources Results of Operations Critical Accounting Policies Commonly Used Terms “Current quarter” refers to the three months ended March 31, 2026, our third quarter of fiscal year 2026. “Year-ago quarter” refers to the three months ended March 31, 2025, our third quarter of fiscal year 2025. Executive Overview General Evolution Petroleum Corporation is an independent energy company focused on maximizing total returns to its shareholders through the ownership of and investment in onshore oil and natural gas properties in the United States. In support of that objective, our long-term goal is to maximize total shareholder return from a diversified portfolio of long-life oil and natural gas properties built through acquisitions and through selective development opportunities, production enhancements, and other exploitation efforts on our oil and natural gas properties. Our oil and natural gas properties consist primarily of non-operated working and mineral interests in the following areas (as well as small overriding royalty and mineral interests in Texas and Louisiana): ● Our non-operated working interests and mineral interests in the SCOOP and STACK plays consist of oil and natural gas producing properties in the Anadarko basin, where we hold an approximate 2.7% average net working interest with an associated 2.0% average net revenue interest located on approximately 103,700 gross (4,200 net) acres (approximately 97% held by production) and a separate approximate 0.6% average net royalty interests located on approximately 5,500 net royalty acres across Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties in Oklahoma. The oil and natural gas properties are primarily operated by Continental Resources, Inc., Ovintiv USA Inc. and EOG Resources, Inc. with approximately 40% of wells operated by other operators. Production from our SCOOP/STACK properties for the nine months ended March 31, 2026 is comprised of 55% natural gas, 24% crude oil, and 21% NGLs. ● Our non-operated interests in the Chaveroo Field consist of a 50% net working interest, with an average associated 41% average net revenue interest, in approximately 4,500 gross (2,300 net) acres all held by production, associated with six development blocks, with the right to acquire the same working interest in additional development locations and associated acreage at a fixed price. The field is operated by PEDEVCO Corp. (“PEDEVCO”). Production from our Chaveroo Field properties for the nine months ended March 31, 2026 is comprised of 100% crude oil. ● Our non-operated interests in the Jonah Field, a natural gas and NGL property in Sublette County, Wyoming, consist of approximately 20% average net working interest and approximately 15% average net revenue interest located on approximately 5,300 gross (950 net) acres all held by production. The properties are operated by Jonah Energy. Production from our Jonah Field properties for the nine months ended March 31, 2026 is comprised of 89% natural gas, 6% NGLs, and 5% crude oil. ● Our non-operated interests in the Williston Basin, an oil and natural gas producing property, consist of approximately 39% average net working interest and approximately 33% average net revenue interest located on approximately 138,200 gross (41,300 net) acres (approximately 97% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota. The properties are operated by Foundation Energy 25 Table of Contents Management. Production from our Williston Basin properties for the nine months ended March 31, 2026 is comprised of 72% crude oil, 17% NGL, and 11% natural gas. ● Our non-operated working interests and overriding royalty interests in the Barnett Shale, a natural gas and NGL producing shale reservoir, consist of approximately 17% average net working interest and approximately 14% average net revenue interest (inclusive of the overriding royalty interests). The approximately 123,800 gross (21,000 net) acres are held by production across nine North Texas counties. The oil and natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by six other operators. Production from our Barnett Shale properties for the nine months ended March 31, 2026 is comprised of 73% natural gas, 26% NGLs, and 1% crude oil. ● Our non-operated interests in the Hamilton Dome Field, a secondary recovery field utilizing water injection wells to pressurize the reservoir, consist of approximately 24% average net working interest, with an associated 20% average net revenue interest (inclusive of a small overriding royalty interest). The 5,900 gross acre unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company, who owns the majority of the remaining working interest in the Hamilton Dome Field. The Hamilton Dome Field is located in the southwest region of the Big Horn Basin in northwest Wyoming. Production from our Hamilton Dome Field properties for the nine months ended March 31, 2026 is comprised of 100% crude oil. ● Our non-operated working interests and overriding royalty interests in the Delhi Field, a CO2-EOR project, consist of approximately 24% average net working interest, with an associated 19% average net revenue interest and separate overriding royalty and mineral interests of approximately 7% yielding a total average net revenue interest of approximately 26%. The field is operated by Denbury Onshore LLC, a subsidiary of Exxon Mobil Corporation. The 13,600 gross acre unitized Delhi Field, of which we hold approximately 3,200 net acres, is located in northeast Louisiana in Franklin, Madison, and Richland Parishes. Production from our Delhi Field properties for the nine months ended March 31, 2026 is comprised of 80% crude oil and 20% NGLs. ● Our non-operated working interests in TexMex consists of oil and natural gas producing properties where we hold an approximate 42% net working interest and 35% average net revenue interest located on approximately 27,800 gross (11,200 net) acres (all held by production) primarily in Lea, Eddy and Chaves Counties, New Mexico and Stephens County, Texas. The oil and natural gas properties are operated by Texian Operating Company. Production from our TexMex properties for the nine months ended March 31, 2026 is comprised of 58% crude oil and 42% natural gas. Recent Developments Dividend Declaration On May 11, 2026, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable June 30, 2026. ​ Purchase of Louisiana Minerals From December 2025 through March 2026, we acquired mineral and royalty interests in multiple parishes across Louisiana from various private sellers for cash consideration totaling $5.0 million, including capitalized direct transaction costs (“Louisiana Minerals”). The mineral acreage in Louisiana primarily consists of proved undeveloped acreage targeting the Bossier/Haynesville Shales and is currently being actively developed by operators in the area. The acquisitions were considered asset acquisitions and funded with cash on hand and sales from our ATM Sales Agreements. Senior Secured Credit Facility 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 26 Table of Contents granted us additional time to enter into further commodity hedges to meet the hedging requirements under the Senior Secured Credit Facility. 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 $0.8 million related to net cash flows earned on the properties from the effective date of May 1, 2025 to the closing date. We accounted for the transaction as an asset acquisition and the allocation of the purchase price was $12.5 million to proved oil and natural gas properties, subject to amortization, and $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. Subsequent to the third fiscal quarter of 2026, we entered into a purchase and sale agreement with a private buyer for the sale of a portion of our non-core, non-producing net royalty acres. The total sale price for the acreage is approximately $3.3 million, subject to customary closing conditions. The divestiture is expected to close in the fourth fiscal quarter of 2026. Risks and uncertainties 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 as well as commodity pricing. Any related significant declines in crude oil, natural gas, and NGL prices could lead to proved property impairments in the future. Any significant increases in commodity 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. ​ At times, we do maintain cash balances in excess of the U.S. Federal Deposit Insurance Corporation (“FDIC”); however, we believe our bank counterparty to be financially sound. We also utilize insured cash sweep deposits to maximize the amount of our cash that is protected by FDIC insurance. We also rely heavily on our third-party operators who manage their own liquidity with various financial institutions. In 2022, the Federal Reserve took actions to raise interest rates in an attempt to constrain inflation and slow the economy. In 2024 and 2025, the Federal Reserve has taken action to 27 Table of Contents slowly drop interest rates as inflationary pressures in the United States economy have begun to subside, but it is uncertain how recent trade policies and tariffs by the United States and foreign governments or other geopolitical events including ongoing conflicts, will impact inflation and the economy. ​ Currently, our oil and natural gas properties are operated by third-party operators and involve other third-party working interest owners. As a result, we have limited ability to influence the operation or future development of such properties. Despite these uncertainties, we remain focused on our long-term objectives and continue to be proactive with our third-party operators to review the management of capital expenditures. Liquidity and Capital Resources As of March 31, 2026, we had $2.6 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 at June 30, 2025. Our primary sources of liquidity and capital resources during the nine months ended March 31, 2026 were cash provided by operations, net borrowings under our Senior Secured Credit Facility, and net proceeds from the ATM Sales Agreements. Our primary uses of liquidity and capital resources for the nine months ended March 31, 2026 were cash used to fund our SCOOP/STACK Minerals Acquisition and Louisiana Minerals, cash dividend payments to our common stockholders, and development capital expenditures. As of March 31, 2026, working capital was a deficit of $10.6 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 March 31, 2026, we had $56.5 million of indebtedness, $0.8 million of letters of credit outstanding, and available capacity of $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 nine months ended March 31, 2026 and 2025, the weighted average interest on our borrowings was 6.78% and 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 March 31, 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 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 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 28 Table of Contents 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 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 $7.7 million as of March 31, 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 nine months ended March 31, 2026, we sold a total of approximately 1.1 million shares of our common stock under the ATM Sales Agreements for net proceeds of approximately $4.7 million, net of $0.2 million of offering costs incurred. Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 50 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 May 11, 2026, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on June 15, 2026 and payable on June 30, 2026. ​ Capital Expenditures During the nine months ending March 31, 2026, we incurred $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 eight gross wells were brought online during the nine months ended March 31, 2016, three gross wells are currently in 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 eleven gross wells online, including the eight 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. Full Cost Pool Ceiling Test 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 29 Table of Contents ceiling test as of March 31, 2026 were $63.80 per barrel of oil, $3.72 per MMBtu of natural gas and $22.50 per barrel of NGLs. As of March 31, 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 March 31, 2026 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 April and May 2026, which are more reflective of recent prices trends, to calculate a trailing 12-month average price of $70.06 per barrel of oil and $3.58 per MMBtu of natural gas, and keeping all other factors constant, the ceiling test calculation as of the fourth 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. Overview of Cash Flow Activities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nine Months Ended March 31, ​ ​ ​ ​ ​ ​ ​ 2026 ​ ​ ​ 2025 ​ ​ ​ Change Cash flows provided by operating activities ​ $ 16,719 ​ $ 22,596 ​ $ (5,877) Cash flows used in investing activities ​ ​ (27,228) ​ ​ (10,053) ​ ​ (17,175) Cash flows provided by (used in) financing activities ​ ​ 10,618 ​ ​ (13,388) ​ ​ 24,006 Net increase (decrease) in cash and cash equivalents ​ $ 109 ​ $ (845) ​ $ 954 Cash provided by operating activities for the nine months ended March 31, 2026 decreased $5.9 million compared to the nine months ended March 31, 2025 primarily due a decrease in revenues of $2.6 million from the prior period and increases in our interest expense and realized losses on derivative contracts. Interest expense increased $0.6 million and in the current period we had net derivative realized losses of $0.6 million compared to realized 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 nine months ended March 31, 2026 increased $17.2 million compared to the nine months ended March 31, 2025 primarily due to the closing of the SCOOP/STACK Minerals Acquisition in August 2025 and Louisiana Minerals from December 2025 through March 2026. Net cash flows provided by financing activities for the nine months ended March 31, 2026 were $10.6 million compared to net cash flows used in financing activities of $13.4 million for the nine months ended March 31, 2025. For the nine months ended March 31, 2026, 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 $4.8 million, after deducting $0.1 million of issuance fees paid, and paid $12.6 million in cash dividends to our common stockholders. For the nine months ended March 31, 2025, we paid $12.2 million in cash dividends to our common stockholders, 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 Agreements of approximately $3.1 million, after deducting $0.3 million of fees for due diligence incurred with the offering. ​ 30 Table of Contents Results of Operations Three Months Ended March 31, 2026 and 2025 We reported net losses of $8.9 million and $2.2 million for the three months ended March 31, 2026 and 2025, respectively. The following table summarizes the comparison of financial information for the periods presented: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended ​ ​ ​ ​ ​ ​ ​ ​ March 31, ​ ​ ​ ​ ​ ​ (in thousands, except per unit and per BOE amounts) ​ ​ ​ 2026 ​ 2025 ​ ​ ​ Variance ​ ​ ​ Variance % Net income (loss) ​ $ (8,932) ​ $ (2,179) ​ $ (6,753) ​ 309.9 % Revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil ​ ​ 10,474 ​ ​ 11,769 ​ ​ (1,295) ​ (11.0) % Natural gas ​ ​ 7,284 ​ ​ 7,790 ​ ​ (506) ​ (6.5) % Natural gas liquids ​ ​ 2,410 ​ ​ 3,002 ​ ​ (592) ​ (19.7) % Total revenues ​ ​ 20,168 ​ ​ 22,561 ​ ​ (2,393) ​ (10.6) % Operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Ad valorem and production taxes ​ ​ 1,317 ​ ​ 1,473 ​ ​ (156) ​ (10.6) % Gathering, transportation, and other costs ​ ​ 2,834 ​ ​ 2,913 ​ ​ (79) ​ (2.7) % Other lease operating costs ​ ​ 8,808 ​ ​ 9,002 ​ ​ (194) ​ (2.2) % Depletion, depreciation, and accretion: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Depletion of full cost proved oil and natural gas properties ​ ​ 4,900 ​ ​ 4,607 ​ ​ 293 ​ 6.4 % Accretion of asset retirement obligations ​ ​ 394 ​ ​ 407 ​ ​ (13) ​ (3.2) % General and administrative expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ General and administrative ​ ​ 1,878 ​ ​ 1,931 ​ ​ (53) ​ (2.7) % Stock-based compensation ​ ​ 595 ​ ​ 642 ​ ​ (47) ​ (7.3) % Other income (expense): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net gain (loss) on derivative contracts ​ ​ (9,869) ​ ​ (3,802) ​ ​ (6,067) ​ 159.6 % Interest and other income ​ ​ 24 ​ ​ 55 ​ ​ (31) ​ (56.4) % Interest expense ​ ​ (960) ​ ​ (705) ​ ​ (255) ​ 36.2 % Income tax (expense) benefit ​ ​ 2,431 ​ ​ 687 ​ ​ 1,744 ​ 253.9 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Production: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil (MBBL) ​ ​ 177 ​ ​ 172 ​ ​ 5 ​ 2.9 % Natural gas (MMCF) ​ ​ 1,968 ​ ​ 2,011 ​ ​ (43) ​ (2.1) % Natural gas liquids (MBBL) ​ ​ 98 ​ ​ 93 ​ ​ 5 ​ 5.4 % Equivalent (MBOE)(1) ​ ​ 603 ​ ​ 600 ​ ​ 3 ​ 0.5 % Average daily production (BOEPD)(1) ​ ​ 6,700 ​ ​ 6,667 ​ ​ 33 ​ 0.5 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average price per unit(2): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil (BBL) ​ $ 59.18 ​ $ 68.42 ​ $ (9.24) ​ (13.5) % Natural gas (MCF) ​ ​ 3.70 ​ ​ 3.87 ​ ​ (0.17) ​ (4.4) % Natural Gas Liquids (BBL) ​ ​ 24.59 ​ ​ 32.28 ​ ​ (7.69) ​ (23.8) % Equivalent (BOE)(1) ​ ​ 33.45 ​ ​ 37.60 ​ ​ (4.15) ​ (11.0) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average cost per unit: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Ad valorem and production taxes ​ ​ 2.18 ​ ​ 2.46 ​ ​ (0.28) ​ (11.4) % Gathering, transportation, and other costs ​ ​ 4.70 ​ ​ 4.86 ​ ​ (0.16) ​ (3.3) % Other lease operating costs ​ ​ 14.61 ​ ​ 15.00 ​ ​ (0.39) ​ (2.6) % Depletion of full cost proved oil and natural gas properties ​ ​ 8.13 ​ ​ 7.68 ​ ​ 0.45 ​ 5.9 % General and administrative expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ General and administrative ​ ​ 3.11 ​ ​ 3.22 ​ ​ (0.11) ​ (3.4) % Stock-based compensation ​ ​ 0.99 ​ ​ 1.07 ​ ​ (0.08) ​ (7.5) % (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. ​ 31 Table of Contents Revenues Crude oil, natural gas and NGL revenues were $20.2 million and $22.6 million for the three months ended March 31, 2026 and 2025, respectively, with the decrease in revenues due to a decrease in our average realized price per BOE partially offset by a 0.5% increase in production volumes. Our average realized commodity price (excluding the impact of derivative contracts) for the three months ended March 31, 2026 decreased approximately $4.15 per BOE, or 11.0%, over the prior year period. Average daily equivalent production was primarily flat quarter over quarter. Increased production from our SCOOP/STACK Minerals Acquisition and TexMex Acquisition was predominately offset by downtime at our other fields. In January 2026, multiple fields were impacted by heavy ice storms and power outages which shut-in production multiple days. The current quarter oil revenue at Delhi Field was also impacted by $1.2 million of prior period adjustments for transportation charges due to a new marketing contract entered into by the operator dating back to December 2024. During the current quarter, decreases in natural gas revenues at Jonah Field and Barnett Shale were driven by their declines in field differentials, which declined on average by $1.96 per Mcf and $0.90 per Mcf, respectively, when compared to Henry Hub in the prior year period. ​ Lease Operating Costs Ad valorem and production taxes were $1.3 million and $1.5 million, respectively, for the three months ended March 31, 2026 and 2025. The decrease is primarily due to lower commodity prices received. On a per unit basis, ad valorem and production taxes were $2.18 per BOE and $2.46 per BOE for the three months ended March 31, 2026 and 2025, respectively. Gathering, transportation and other costs were $2.8 million for the three months ended March 31, 2026 compared to $2.9 million for the three months ended March 31, 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 $4.70 per BOE and $4.86 per BOE for the three months ended March 31, 2026 and 2025, respectively. Other lease operating costs were $8.8 million for the three months ended March 31, 2026 compared to $9.0 million for the three months ended March 31, 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 March 31, 2025, we had net CO2 purchases of $1.5 million. Partially offsetting the overall decrease in other lease operating costs were increases due to the TexMex Acquisition in April 2025. During the current quarter, 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 $14.61 per BOE for the three months ended March 31, 2026 from $15.00 per BOE in the three months ended March 31, 2025. Depletion of Full Cost Proved Oil and Natural Gas Properties Depletion expense increased from $4.6 million for the three months ended March 31, 2025 to $4.9 million for the three months ended March 31, 2026 primarily due to an increase in the depletion rate and decrease in reserves volumes. On a per unit basis, depletion expense was $8.13 per BOE and $7.68 per BOE for the three months ended March 31, 2026 and 2025, respectively. General and Administrative Expenses General and administrative expenses were $1.9 million for each of the three months ended March 31, 2026 and 2025. On a per unit basis, general and administrative expenses were $3.11 per BOE and $3.22 per BOE for the three months ended March 31, 2026 and 2025, respectively. 32 Table of Contents Net Gain (Loss) on Derivative Contracts 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 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 March 31, 2026, we had $3.1 million derivative assets, $2.4 million of which was classified as current, and $9.3 million derivative liabilities, $8.5 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. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended ​ ​ ​ ​ ​ ​ ​ ​ March 31, ​ ​ ​ ​ ​ ​ (in thousands, except per unit and per BOE amounts) ​ ​ ​ 2026 ​ ​ ​ 2025 ​ ​ ​ Variance ​ ​ ​ Variance % Realized gain (loss) on derivative contracts ​ $ (2,248) ​ $ 124 ​ $ (2,372) ​ (1,912.9) % Unrealized gain (loss) on derivative contracts ​ ​ (7,621) ​ ​ (3,926) ​ ​ (3,695) ​ 94.1 % Total net gain (loss) on derivative contracts ​ $ (9,869) ​ $ (3,802) ​ $ (6,067) ​ 159.6 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average realized crude oil price per BBL ​ $ 59.18 ​ $ 68.42 ​ $ (9.24) ​ (13.5) % Cash effect of oil derivative contracts per BBL ​ ​ (6.18) ​ ​ 0.34 ​ ​ (6.52) ​ (1,917.6) % Crude oil price per BBL (including impact of realized derivatives) ​ $ 53.00 ​ $ 68.76 ​ $ (15.76) ​ (22.9) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average realized natural gas price per MCF ​ $ 3.70 ​ $ 3.87 ​ $ (0.17) ​ (4.4) % Cash effect of natural gas derivative contracts per MCF ​ ​ (0.59) ​ ​ 0.03 ​ ​ (0.62) ​ (2,067) % Natural gas price per MCF (including impact of realized derivatives) ​ $ 3.11 ​ $ 3.90 ​ $ (0.79) ​ (20.3) % ​ Interest Expense Interest expense increased $0.3 million for the three months ended March 31, 2026 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. Income Tax (Expense) Benefit For the three months ended March 31, 2026, we recognized an income tax benefit of $2.4 million on net losses before income taxes of $11.4 million compared to income tax benefit of $0.7 million on net losses before income taxes of $2.9 million for the three months ended March 31, 2025. The effective tax rates were 21.4% and 24.0% for three months ended March 31, 2026 and 2025, respectively. 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. 33 Table of Contents Nine Months Ended March 31, 2026 and 2025 We reported net losses of $7.0 million and $1.9 million for the nine months ended March 31, 2026 and 2025, respectively. The following table summarizes the comparison of financial information for the periods presented: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nine Months Ended ​ ​ ​ ​ ​ ​ ​ ​ March 31, ​ ​ ​ ​ ​ ​ (in thousands, except per unit and per BOE amounts) ​ ​ ​ 2026 ​ ​ ​ 2025 ​ ​ ​ Variance ​ ​ ​ Variance % Net income (loss) ​ $ (7,043) ​ $ (1,939) ​ $ (5,104) ​ 263.2 % Revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil ​ ​ 34,042 ​ ​ 38,269 ​ ​ (4,227) ​ (11.0) % Natural gas ​ ​ 20,625 ​ ​ 17,868 ​ ​ 2,757 ​ 15.4 % Natural gas liquids ​ ​ 7,468 ​ ​ 8,595 ​ ​ (1,127) ​ (13.1) % Total revenues ​ ​ 62,135 ​ ​ 64,732 ​ ​ (2,597) ​ (4.0) % Operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Ad valorem and production taxes ​ ​ 3,325 ​ ​ 4,328 ​ ​ (1,003) ​ (23.2) % Gathering, transportation, and other costs ​ ​ 8,393 ​ ​ 8,592 ​ ​ (199) ​ (2.3) % Other lease operating costs ​ ​ 25,838 ​ ​ 25,051 ​ ​ 787 ​ 3.1 % Depletion, depreciation, and accretion: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Depletion of full cost proved oil and natural gas properties ​ ​ 15,992 ​ ​ 14,956 ​ ​ 1,036 ​ 6.9 % Accretion of asset retirement obligations ​ ​ 1,182 ​ ​ 1,216 ​ ​ (34) ​ (2.8) % General and administrative expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ General and administrative ​ ​ 5,645 ​ ​ 5,894 ​ ​ (249) ​ (4.2) % Stock-based compensation ​ ​ 1,745 ​ ​ 1,860 ​ ​ (115) ​ (6.2) % Other income (expense): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net gain (loss) on derivative contracts ​ ​ (5,453) ​ ​ (3,223) ​ ​ (2,230) ​ 69.2 % Interest and other income ​ ​ 46 ​ ​ 164 ​ ​ (118) ​ (72.0) % Interest expense ​ ​ (2,880) ​ ​ (2,292) ​ ​ (588) ​ 25.7 % Income tax (expense) benefit ​ ​ 1,229 ​ ​ 577 ​ ​ 652 ​ 113.0 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Production: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil (MBBL) ​ ​ 577 ​ ​ 555 ​ ​ 22 ​ 4.0 % Natural gas (MMCF) ​ ​ 6,359 ​ ​ 6,364 ​ ​ (5) ​ (0.1) % Natural gas liquids (MBBL) ​ ​ 318 ​ ​ 311 ​ ​ 7 ​ 2.3 % Equivalent (MBOE)(1) ​ ​ 1,955 ​ ​ 1,927 ​ ​ 28 ​ 1.5 % Average daily production (BOEPD)(1) ​ ​ 7,135 ​ ​ 7,033 ​ ​ 102 ​ 1.5 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average price per unit(2): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Crude oil (BBL) ​ $ 59.00 ​ $ 68.95 ​ $ (9.95) ​ (14.4) % Natural gas (MCF) ​ ​ 3.24 ​ ​ 2.81 ​ ​ 0.43 ​ 15.3 % Natural Gas Liquids (BBL) ​ ​ 23.48 ​ ​ 27.64 ​ ​ (4.16) ​ (15.1) % Equivalent (BOE)(1) ​ ​ 31.78 ​ ​ 33.59 ​ ​ (1.81) ​ (5.4) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average cost per unit: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Ad valorem and production taxes ​ $ 1.70 ​ $ 2.25 ​ $ (0.55) ​ (24.4) % Gathering, transportation, and other costs ​ ​ 4.29 ​ ​ 4.46 ​ ​ (0.17) ​ (3.8) % Other lease operating costs ​ ​ 13.22 ​ ​ 13.00 ​ ​ 0.22 ​ 1.7 % Depletion of full cost proved oil and natural gas properties ​ ​ 8.18 ​ ​ 7.76 ​ ​ 0.42 ​ 5.4 % General and administrative expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ General and administrative ​ ​ 2.89 ​ ​ 3.06 ​ ​ (0.17) ​ (5.6) % Stock-based compensation ​ ​ 0.89 ​ ​ 0.97 ​ ​ (0.08) ​ (8.2) % (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. ​ 34 Table of Contents Revenues Crude oil, natural gas and NGL revenues were $62.1 million and $64.7 million for the nine months ended March 31, 2026 and 2025, respectively, with the decrease in revenues due to decreases in our average realized price per BOE partially offset by increases in production volumes. Average daily equivalent production increased 1.5% from 7,033 BOEPD in the prior year period to 7,135 BOEPD in the current period primarily as a result of production from our SCOOP/STACK Minerals Acquisition in August 2025 and TexMex Acquisition in April 2025 partially offset by downtime at our other fields. In January 2026, multiple fields were impacted by heavy ice storms and power outages which shut-in production multiple days. Our average realized commodity price (excluding the impact of derivative contracts) for the nine months ended March 31, 2026 decreased approximately $1.81 per BOE, or 5.4%, over the prior year period as our realized crude oil decreased 14.4% and realized NGL prices decreased 15.1% from the nine months ended March 31, 2025. The current period oil revenue at Delhi Field was also impacted by $1.2 million of prior period adjustments for transportation charges due to a new marketing contract entered into by the operator dating back to December 2024. The overall decrease in our crude oil and NGL realized prices was partially offset by a 15.3% increase in our realized natural gas prices over the prior period. ​ Lease Operating Costs Ad valorem and production taxes were $3.3 million and $4.3 million for the nine months ended March 31, 2026 and 2025, respectively. The decrease is primarily related to a $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. On a per unit basis, ad valorem and production taxes were $1.70 per BOE and $2.25 per BOE for the nine months ended March 31, 2026 and 2025, respectively. Gathering, transportation and other costs were $8.4 million for the nine months ended March 31, 2026 compared to $8.6 million for the nine months ended March 31, 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 partially offset by increased natural gas sales at Barnett Shale. On a per unit basis, gathering, transportation and other costs were $4.29 per BOE and $4.46 per BOE for the nine months ended March 31, 2026 and 2025, respectively. Other lease operating costs were $25.8 million for the nine months ended March 31, 2026 compared to $25.1 million for the nine months ended March 31, 2025. Other lease operating costs increased primarily due to the TexMex Acquisition in April 2025, which increased other lease operating costs by $3.8 million over the prior year period. Partially offsetting the overall increase in other lease operating costs is the cessation of CO2 purchases at Delhi late during the third quarter of fiscal 2025. For the nine months ended March 31, 2025, we had net CO2 purchases of $2.6 million. On a per unit basis, other lease operating costs increased to $13.22 per BOE for the nine months ended March 31, 2026 from $13.00 per BOE in the nine months ended March 31, 2025. Depletion of Full Cost Proved Oil and Natural Gas Properties Depletion expense increased from $15.0 million for the nine months ended March 31, 2025 to $16.0 million for the nine months ended March 31, 2026 primarily due to an increase in the depletion rate and decrease in reserves volumes. On a per unit basis, depletion expense was $8.18 per BOE and $7.76 per BOE for the nine months ended March 31, 2026 and 2025, respectively. General and Administrative Expenses General and administrative expenses for the nine months ended March 31, 2026 and 2025 were $5.6 million and $5.9 million, respectively. The decrease in the current period is primarily due to a decrease in professional fees. On a per unit basis, general and administrative expenses were $2.89 per BOE and $3.06 per BOE for the nine months ended March 31, 2026 and 2025, respectively. 35 Table of Contents Stock-based Compensation Expense Stock-based compensation expense for the nine months ended March 31, 2026 was $1.7 million compared to $1.9 million for the year-ago period. The decrease is due to the vesting of sign-on awards granted in prior years. Net Gain (Loss) on Derivative Contracts 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 March 31, 2026, we had $3.1 million derivative assets, $2.4 million of which was classified as current, and $9.3 million derivative liabilities, $8.5 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. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nine Months Ended ​ ​ ​ ​ ​ ​ ​ ​ March 31, ​ ​ ​ ​ ​ ​ (in thousands, except per unit and per BOE amounts) ​ ​ ​ 2026 ​ ​ ​ 2025 ​ ​ ​ Variance ​ ​ ​ Variance % Realized gain (loss) on derivative contracts ​ $ (578) ​ $ 203 ​ $ (781) ​ (384.7) % Unrealized gain (loss) on derivative contracts ​ ​ (4,875) ​ ​ (3,426) ​ ​ (1,449) ​ 42.3 % Total net gain (loss) on derivative contracts ​ $ (5,453) ​ $ (3,223) ​ $ (2,230) ​ 69.2 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average realized crude oil price per BBL ​ $ 59.00 ​ $ 68.95 ​ $ (9.95) ​ (14.4) % Cash effect of oil derivative contracts per BBL ​ ​ (0.94) ​ ​ 0.25 ​ ​ (1.19) ​ (476.0) % Crude oil price per BBL (including impact of realized derivatives) ​ $ 58.06 ​ $ 69.20 ​ $ (11.14) ​ (16.1) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average realized natural gas price per MCF ​ $ 3.24 ​ $ 2.81 ​ $ 0.43 ​ 15.3 % Cash effect of natural gas derivative contracts per MCF ​ ​ (0.01) ​ ​ 0.01 ​ ​ (0.02) ​ (200.0) % Natural gas price per MCF (including impact of realized derivatives) ​ $ 3.23 ​ $ 2.82 ​ $ 0.41 ​ 14.5 % Interest Expense Interest expense increased $0.6 million for the nine months ended March 31, 2026 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. Income Tax (Expense) Benefit For the nine months ended March 31, 2026, we recognized income tax benefit of $1.2 million on net losses before income taxes of $8.3 million compared to income tax benefit of $0.6 million on net losses before income taxes of $2.5 million for the nine months ended March 31, 2025. The effective tax rates were 14.9% and 22.9% for nine months ended March 31, 2026 and 2025, respectively. 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. 36 Table of Contents Critical Accounting Policies and Estimates Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements. The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires that we select certain accounting policies and make estimates and assumptions that affect the reported amounts of the assets, liabilities, and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported amounts of revenues and expenses during the reporting period. These policies, together with our estimates, have a significant effect on our unaudited condensed consolidated financial statements. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended June 30, 2025.