# EVOLUTION PETROLEUM CORP (EPM) FY 2026 MD&A

Verbatim Item 7 Management's Discussion and Analysis from EVOLUTION PETROLEUM CORP's 10-K for fiscal year 2026.

SEC filing source: https://www.sec.gov/Archives/edgar/data/1006655/000110465926108258/epm-20260630x10k.htm
Accession: 0001104659-26-108258
Filing date: 2026-09-16
Report date: 2026-06-30
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Published MD&A gate trimmed front/tail over-capture.
Confidence: high

Company profile: /company/EPM/
All MD&A years: /company/EPM/mda/
Previous year: /company/EPM/mda/fy2025/ (FY 2025)

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Executive Overview

Liquidity and Capital Resources

Results of Operations

Critical Accounting Policies and Estimates

Executive Overview

General

We are an independent energy company focused on acquiring and developing long-lived oil and natural gas properties in the United States. Our diversified portfolio consists primarily of non-operated working interests and mineral and royalty interests across several leading producing basins.

Our non-operated model allows us to invest alongside experienced operators, participate in a broad range of development opportunities and maintain flexibility in the timing and allocation of capital. Our mineral and royalty interests provide additional exposure to production and future development, generally without associated lifting expenses or drilling and completions costs.

The geographic, commodity, operator and ownership diversity of our asset base reduces our reliance on any single property, basin or development program. It also provides multiple avenues for allocating capital, including acquiring producing working and mineral interests, participating in and benefiting from attractive operator-led projects and pursuing development opportunities within our existing assets.

We seek to maximize total shareholder value through disciplined acquisitions, selective participation in attractive development projects, a conservative balance sheet and the return of capital to shareholders.

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):

[[GREPCENT_TABLE]]
[["","\u25cf","Our non-operated working 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 2.6% average net working interest with an associated 2.0% average net revenue interest located on approximately 101,100 gross (4,000 net) acres (all held by production) and a separate approximate 0.6% average net royalty interests located on approximately 8,600 gross (1,800 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., Validus Energy, and EOG Resources, Inc. with approximately 34% of wells operated by other operators."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","Our non-operated working 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. (\u201cPEDEVCO\u201d)."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","Our non-operated working 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."]]
[[/GREPCENT_TABLE]]

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[[GREPCENT_TABLE]]
[["","\u25cf","Our non-operated working 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 133,800 gross (40,100 net) acres (approximately 99% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota. The properties are operated by Foundation Energy Management."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","Our non-operated working 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, until sold to Eagleridge Operating, LLC in June 2026, with approximately 19% of wells operated by five other operators."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","Our non-operated working 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."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","Our non-operated working 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 Delhi Field is comprised of 13,600 gross unitized acres, of which we hold approximately 3,200 net acres, and is located in northeast Louisiana in Franklin, Madison, and Richland Parishes."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","Our mineral and royalty interest in the Haynesville/Bossier Shale, consists of a mix of natural gas producing wells, drilled but not yet producing wells, and proved undeveloped acreage with an approximate average 0.3% net royalty interest. Our mineral and royalty interest span across an approximate 3,600 gross (465 net) acres located in Bossier, Caddo, DeSoto, Red River and Sabine parishes in Louisiana."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","Our non-operated working interest 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."]]
[[/GREPCENT_TABLE]]

Recent Developments

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Dividend Declaration

​

On September 10, 2026, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable September 30, 2026.

Purchase of Permian Minerals

​

On August 20, 2026, we completed the acquisition of mineral and royalty interests in the core Midland Basin of the Permian Basin from a non-affiliated private seller for a total purchase price of $16.0 million (the “Permian Minerals Acquisition”), subject to customary post-closing adjustments. The Permian Minerals Acquisition has an effective date of August 1, 2026. We funded the purchase price for the Permian Minerals Acquisition with a combination of net proceeds from our concurrent public equity offering and $3.2 million in borrowings under our Senior Secured Credit Facility. The acquired assets include approximately 3,420 net royalty acres across Reagan, Martin, Midland, Glasscock, and Upton Counties, Texas.

​

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Common Stock Offering

​

On August 20, 2026, we completed a public offering of 4.3 million shares of our common stock, at an offering price of $3.25 per share (the “Offering”). We received net proceeds of approximately $12.8 million from the Offering, after deducting underwriting discounts and commissions and estimated offering expenses. Net proceeds from the Offering, together with borrowings under our Senior Secured Credit Facility and cash on hand, were used to fund the Permian Minerals Acquisition.

Senior Secured Credit Facility

On August 20, 2026, we entered into a letter agreement with MidFirst Bank pursuant to which the borrowing base on our Senior Secured Credit Facility was temporarily increased from $65.0 million to $73.0 million from August 20, 2026 until October 20, 2026, unless redetermined earlier in accordance with the credit agreement. We currently expect to begin our semi-annual Fall redetermination on or about October 1, 2026.

Previously 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.

Purchase of Louisiana Minerals

From December 2025 through June 2026, we acquired mineral and royalty interests in multiple parishes across Louisiana from various private sellers for cash consideration totaling $6.2 million, including capitalized direct transaction costs (“Louisiana Minerals”). The mineral acreage in Louisiana consists of proved producing wells, drilled but not yet producing wells, and 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.

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.

​

On June 30 2026, we completed the divestiture of a portion of our non-core, non-producing net mineral acres in the SCOOP/STACK with a private buyer. The acreage sold was 3,700 net acres for a total sale price of approximately $3.1 million, before customary post-closing adjustments.

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At-the-Market (“ATM”) Equity Sales Program

​

On October 21, 2024, we entered into an ATM equity 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 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, 2026, we sold a total of

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approximately 1.4 million shares of our common stock under the ATM Sales Agreements for net proceeds of approximately $5.8 million, net of $0.2 million of offering costs incurred. Net proceeds from the 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 Reserves

The following table is a summary of our proved reserves as of June 30, 2026 and 2025:

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Proved Reserves","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b \u200b \u200b","2026","\u200b \u200b \u200b","\u200b","2025","\u200b \u200b \u200b","\u200b","Change"],["Proved Reserves MMBOE","\u200b","\u200b","27.2","\u200b","\u200b","\u200b","27.1","\u200b","\u200b","0.4","%"],["% Developed","\u200b","\u200b","82.2","%","\u200b","\u200b","83.7","%","\u200b","(1.5)","%"],["Liquids %","\u200b","\u200b","54.6","%","\u200b","\u200b","62.2","%","\u200b","(7.6)","%"],["Standardized Measure ($MM)","\u200b","$","156.4","\u200b","\u200b","$","155.2","\u200b","\u200b","0.8","%"]]
[[/GREPCENT_TABLE]]

​

Proved oil equivalent reserves as of June 30, 2026 were 27.2 MMBOE, a 0.1 MMBOE, or 0.4%, increase from the previous year of 27.1 MMBOE. The net increase in total proved reserves was primarily due to 1.6 MMBOE of proved reserves purchased from our SCOOP/STACK Minerals Acquisition and Louisiana Minerals acquisitions as well as extensions of 0.4 MMBOE primarily at SCOOP/STACK and net positive revisions of 0.7 MMBOE partially offset by production roll off of 2.6 MMBOE. Approximately 2.2 MMBOE of upward revisions were in our natural gas reserves were partially offset by approximately 1.4 MMBOE of downward revisions in our oil and NGL reserves. Natural gas reserves increased primarily due to an increase in the SEC trailing 12-month natural gas price of 26.1% from the prior fiscal year. Oil and natural gas liquids downward revisions were a result of a reduction in the economic life of certain oil fields due to increased costs.

​

The Standardized Measure for proved reserves increased 0.8% to $156.4 million, primarily due to our SCOOP/STACK Minerals Acquisition and Louisiana Mineral acquisitions. Partially offsetting the increase are volumes produced and sold. Our proved reserves consist of 39% oil, 45% natural gas, and 16% NGLs; 82.2% are classified as proved developed and 16.3% are proved undeveloped.

Additional property and project information is included under Item 1. Business and in Note 4, “Property and Equipment” and our Supplemental Disclosure about Oil and Natural Gas Properties (unaudited) to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data, and in Exhibit 99.1 and 99.2 of this Form 10-K.

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

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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 of proved properties 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 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 June 30, 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 at June 30, 2025. Our primary sources of liquidity and capital resources during the year ended June 30, 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 year ended June 30, 2026 were cash used to fund our SCOOOP/STACK Minerals Acquisition and Louisiana Minerals, cash dividend payments to our common stockholders, and development capital 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 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. As of June 30, 2026, the Senior Secured Credit Facility had a borrowing base of $65.0 million. As of June 30, 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.

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, 2026 and 2025, the weighted average interest on our borrowings were 6.69% and 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

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covenants, including a hedging covenant discussed below, and events of default. As of June 30, 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.

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. For the year ended June 30, 2026, we sold a total of approximately 1.4 million shares of our common stock under the ATM Sales Agreements for net proceeds of approximately $5.8 million, net of $0.2 million of offering costs incurred.

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 Agreements.

Consistent with our business strategy, we are constantly pursuing new growth opportunities and other transactions to maximize shareholder value and will do so using a targeted mix of capital sourcing. We will continue to pursue acquisitions of oil and natural gas properties, including long-life producing properties with substantial upside potential as well as acquisitions of minerals and royalty interests. As described in “Recent Developments” above, subsequent to our fiscal year end, we completed our Permian Minerals Acquisition on August 20, 2026, for a total purchase price of $16.0 million which was funded with proceeds from the Offering and $3.2 million in borrowings under our Senior Secured Credit Facility. In addition, on August 20, 2026, we entered into a letter agreement with MidFirst Bank pursuant to which the borrowing base on our Senior Secured Credit Facility was temporarily increased from $65.0 million to $73.0 million from August 20, 2026 until October 20, 2026, unless redetermined earlier in accordance with the credit agreement. We currently expect to begin or semi-annual Fall redetermination on or about October 1, 2026. While this increased capacity affords us additional flexibility, we have not drawn on it to date. After taking into account the Offering, additional borrowings of $3.5 million under our Senior Secured Credit Facility, and the temporary increase in our revolving borrowing base, we have 40.2 million shares of common stock outstanding and $12.2 million of available capacity under our Senior Secured Credit Facility as of September 1, 2026. We also have an effective shelf registration statement with the SEC under which we are allowed to issue in aggregate up to $500.0 million of debt or equity securities.

Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 51 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 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 10, 2026, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on September 21, 2026 and payable on September 30, 2026.

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Capital Expenditures

For the year ended June 30, 2026, we incurred $5.5 million on development capital expenditures. A majority of our spending occurred at SCOOP/STACK, Chaveroo Field and Hamilton Dome Field. At SCOOP/STACK ten gross wells were brought online during the year ended June 30, 2026. At Chaveroo Field, capital spending was related to converting the wells to rod pumps. As of June 30, 2026, all seven producing wells have been converted to rod pump. At 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 as well as further drilling at SCOOP/STACK. Overall, for fiscal year 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, and drilling at Chaveroo Field. Our expected capital expenditures for the next 12 months include bringing approximately ten gross wells online at SCOOP/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.

As of June 30, 2026, our PUD reserves included 4.8 MMBOE of reserves and approximately $74.8 million of future development costs primarily associated with the Chaveroo Field, Williston Basin, and SCOOP/STACK properties.

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

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 ceiling test as of June 30, 2026 were $72.93 per barrel of oil, $3.62 per MMBtu of natural gas and $27.50 per barrel of NGLs. As of June 30, 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 June 30, 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 tests in future 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 as commodity prices are volatile and unpredictable. Using 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 constant, the ceiling test calculation as of the fourth quarter of fiscal year 2026 would not have generated a ceiling test impairment.

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Overview of Cash Flow Activities

[[GREPCENT_TABLE]]
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[[/GREPCENT_TABLE]]

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Cash provided by operating activities decreased $9.5 million during the fiscal year ended June 30, 2026 compared to fiscal year ended June 30, 2025 primarily due to $3.8 million of realized losses on our derivative contracts compared to realized gains of $1.0 million in the prior year, and changes in the timing of our working capital. Refer to “Results of Operations” below for further information.

Cash used in investing activities for the year ended June 30, 2025 increased $5.5 million from the prior year primarily due to the closing of the SCOOP/STACK Minerals Acquisition in August 2025 and Louisiana Minerals acquisitions throughout the fiscal year, totaling $23.0 million in net cash spent on acquisitions. In addition, cash expenditures for development and capital expenditures were $7.3 million which included drilling and completing ten gross wells at SCOOP / STACK and rod pump conversions, facility upgrades and consolidations at Chaveroo and Hamilton Dome. In fiscal 2026, we also collected $3.1 million in proceeds from the sale of unproved acreage at SCOOP / STACK. In the prior year, net cash spent on the TexMex Acquisition was $9.0 million and development capital expenditures were $12.6 million. In the prior fiscal year capital expenditures included drilling and completing four gross (2.0 net) Chaveroo wells and thirteen gross (0.14 net) SCOOP/STACK wells.

Net cash flows provided by financing activities for the year ended June 30, 2026 were $7.3 million compared to net cash flows used in financing activities of $15.3 million for the year ended June 30, 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.

​

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Results of Operations

Years Ended June 30, 2026 and 2025

We reported a net loss of $2.4 million and net income of $1.5 million for the years ended June 30, 2026 and 2025, respectively. The following table summarizes the comparison of financial information for the periods presented:

​

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["","\u200b","Years Ended June 30,","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["(in thousands, except per unit and per BOE amounts)","\u200b \u200b \u200b","2026","\u200b \u200b \u200b","2025","\u200b \u200b \u200b","Variance","\u200b \u200b \u200b","Variance %"],["Net income (loss)","\u200b","$","(2,429)","\u200b","$","1,473","\u200b","$","(3,902)","\u200b","(264.9)","%"],["Revenues:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Crude oil","\u200b","\u200b","50,556","\u200b","\u200b","51,102","\u200b","\u200b","(546)","\u200b","(1.1)","%"],["Natural gas","\u200b","\u200b","25,038","\u200b","\u200b","23,516","\u200b","\u200b","1,522","\u200b","6.5","%"],["Natural gas liquids","\u200b","\u200b","10,749","\u200b","\u200b","11,222","\u200b","\u200b","(473)","\u200b","(4.2)","%"],["Total revenues","\u200b","\u200b","86,343","\u200b","\u200b","85,840","\u200b","\u200b","503","\u200b","0.6","%"],["Operating costs:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Lease operating costs:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Ad valorem and production taxes","\u200b","\u200b","4,763","\u200b","\u200b","5,709","\u200b","\u200b","(946)","\u200b","(16.6)","%"],["Gathering, transportation, and other costs","\u200b","\u200b","11,139","\u200b","\u200b","11,357","\u200b","\u200b","(218)","\u200b","(1.9)","%"],["Other lease operating costs","\u200b","\u200b","34,436","\u200b","\u200b","32,272","\u200b","\u200b","2,164","\u200b","6.7","%"],["Depletion, depreciation, and accretion:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Depletion of full cost proved oil and natural gas properties","\u200b","\u200b","21,197","\u200b","\u200b","20,374","\u200b","\u200b","823","\u200b","4.0","%"],["Accretion of asset retirement obligations","\u200b","\u200b","1,583","\u200b","\u200b","1,619","\u200b","\u200b","(36)","\u200b","(2.2)","%"],["General and administrative expenses:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["General and administrative","\u200b","\u200b","7,401","\u200b","\u200b","7,852","\u200b","\u200b","(451)","\u200b","(5.7)","%"],["Stock-based compensation","\u200b","\u200b","2,344","\u200b","\u200b","2,482","\u200b","\u200b","(138)","\u200b","(5.6)","%"],["Other income (expense):","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Net gain (loss) on derivative contracts","\u200b","\u200b","(2,850)","\u200b","\u200b","473","\u200b","\u200b","(3,323)","\u200b","(702.5)","%"],["Interest and other income","\u200b","\u200b","72","\u200b","\u200b","191","\u200b","\u200b","(119)","\u200b","(62.3)","%"],["Interest expense","\u200b","\u200b","(3,849)","\u200b","\u200b","(2,970)","\u200b","\u200b","(879)","\u200b","29.6","%"],["Income tax (expense) benefit","\u200b","\u200b","718","\u200b","\u200b","(396)","\u200b","\u200b","1,114","\u200b","(281.3)","%"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Production:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Crude oil (MBBL)","\u200b","\u200b","759","\u200b","\u200b","766","\u200b","\u200b","(7)","\u200b","(0.9)","%"],["Natural gas (MMCF)","\u200b","\u200b","8,428","\u200b","\u200b","8,409","\u200b","\u200b","19","\u200b","0.2","%"],["Natural gas liquids (MBBL)","\u200b","\u200b","419","\u200b","\u200b","414","\u200b","\u200b","5","\u200b","1.2","%"],["Equivalent (MBOE)(1)","\u200b","\u200b","2,583","\u200b","\u200b","2,582","\u200b","\u200b","1","\u200b","0.0","%"],["Average daily production (BOEPD)(1)","\u200b","\u200b","7,077","\u200b","\u200b","7,074","\u200b","\u200b","3","\u200b","0.0","%"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Average price per unit(2):","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Crude oil (BBL)","\u200b","$","66.61","\u200b","$","66.71","\u200b","$","(0.10)","\u200b","(0.1)","%"],["Natural gas (MCF)","\u200b","\u200b","2.97","\u200b","\u200b","2.80","\u200b","\u200b","0.17","\u200b","6.1","%"],["Natural Gas Liquids (BBL)","\u200b","\u200b","25.65","\u200b","\u200b","27.11","\u200b","\u200b","(1.46)","\u200b","(5.4)","%"],["Equivalent (BOE)(1)","\u200b","\u200b","33.43","\u200b","\u200b","33.25","\u200b","\u200b","0.18","\u200b","0.5","%"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Average cost per unit:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Operating costs:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Lease operating costs:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Ad valorem and production taxes","\u200b","$","1.84","\u200b","$","2.21","\u200b","$","(0.37)","\u200b","(16.7)","%"],["Gathering, transportation, and other costs","\u200b","\u200b","4.31","\u200b","\u200b","4.40","\u200b","\u200b","(0.09)","\u200b","(2.0)","%"],["Other lease operating costs","\u200b","\u200b","13.33","\u200b","\u200b","12.50","\u200b","\u200b","0.83","\u200b","6.6","%"],["Depletion of full cost proved oil and natural gas properties","\u200b","\u200b","8.21","\u200b","\u200b","7.89","\u200b","\u200b","0.32","\u200b","4.1","%"],["General and administrative expenses:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["General and administrative","\u200b","\u200b","2.87","\u200b","\u200b","3.04","\u200b","\u200b","(0.17)","\u200b","(5.6)","%"],["Stock-based compensation","\u200b","\u200b","0.91","\u200b","\u200b","0.96","\u200b","\u200b","(0.05)","\u200b","(5.2)","%"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(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."]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(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."]]
[[/GREPCENT_TABLE]]

​

​

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Revenues

Crude oil, natural gas and NGL revenues were $86.3 million and $85.8 million for the fiscal years ended June 30, 2026 and 2025, respectively. The increase in revenues is primarily due to the increase in our average realized price per BOE. Our average realized commodity price (excluding the impact of derivative contracts) increased approximately $0.18 per BOE, or 0.5%, for the fiscal year ended June 30, 2026 compared to June 30, 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, 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 0.1% and 5.4% from the prior fiscal year respectively. The current year 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. Average daily equivalent production increased slightly from 7,074 BOEPD to 7,077 BOEPD in the current fiscal year as a result of additional production from our SCOOP/STACK Minerals Acquisition in August 2025 and TexMex Acquisition in April 2025 and newly drilled wells at SCOOP/STACK since the prior year end.

​

Lease Operating Costs

Ad valorem and production taxes were $4.8 million and $5.7 million for the years ended June 30, 2026 and 2025, respectively. The decrease 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 was partially offset by our SCOOP/STACK Minerals Acquisition in August 2025 and our TexMex Acquisition in April 2025. On a per unit basis, ad valorem and production taxes were $1.84 per BOE and $2.21 per BOE for the years ended June 30, 2026 and 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. These costs are gathering, transportation and processing fees we incur primarily for our natural gas producing properties. The decrease is primarily due to the decrease in natural gas sales at Jonah Field. On a per unit basis, gathering, transportation and other costs were $4.31 per BOE and $4.40 per BOE for the years ended June 30, 2026 and 2025, respectively.

Other lease operating costs were $34.4 million for the year ended June 30, 2026 compared to $32.3 million in the prior year. Other lease operating costs increased primarily due to the TexMex Acquisition in April 2025, which increased other lease operating costs by $4.1 million over the prior year period. In addition, the prior year period contained a $1.9 million credit from the operator of one of our Barnett Shale properties due to a joint venture audit. Partially offsetting the overall increase in other lease operating costs is the cessation of CO2 purchases at Delhi late in the third fiscal quarter of 2025. We did not purchase CO2 in the current year but purchased $2.6 million of net CO2 in the prior year. On a per unit basis, other lease operating costs increased to $13.33 per BOE in the current year from $12.50 per BOE in the prior year, primarily due to the TexMex Acquisition. Other lease operating costs were elevated during the fiscal year due to the delay in transfer of operatorship from the previous seller to the current operator as well as an extensive workover program in Texas and New Mexico.

Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased $0.8 million or 4.0% from $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 $8.21 per BOE and $7.89 per BOE for the fiscal years ended June 30, 2026 and 2025, respectively. The depletion rate of our unit of production calculation increased primarily due to an overall increase in our depreciable base due to acquisitions since the prior year period.

General and Administrative Expenses

General and administrative expenses for the fiscal year ended June 30, 2026 decreased $0.5 million, or 5.7%, to $7.4 million compared to $7.9 million for the fiscal year ended June 30, 2025. The decrease primarily relates reduced

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compensation expense in the current year. On a per unit basis, general and administrative expenses were $2.87 per BOE and $3.04 per BOE for the years ended June 30, 2026 and 2025, respectively.

Stock-based Compensation Expenses

Stock-based compensation decreased to $2.3 million for the year ended June 30, 2026 from $2.5 million the prior period. The decrease is due to a reduction in the awards granted in the current fiscal year compared to the prior fiscal year.

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 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 Minerals Acquisition in August 2025, and the corresponding borrowings on our Senior Secured Credit Facility, we were required by terms in our Senior Secured Credit Facility to hedge 75% of our crude oil and 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 commodity prices for natural gas, as of June 30, 2026, resulted in an unrealized gain on the mark-to-market of our hedges. As of June 30, 2026, we had a $2.6 million derivative asset, $2.1 million of which was classified as current, and a $3.1 million derivative liability, $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.

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Years Ended June 30,","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["(in thousands, except per unit and per BOE amounts)","\u200b \u200b \u200b","2026","\u200b \u200b \u200b","2025","\u200b \u200b \u200b","Variance","\u200b \u200b \u200b","Variance %"],["Realized gain (loss) on derivative contracts","\u200b","$","(3,752)","\u200b","$","965","\u200b","$","(4,717)","\u200b","(488.8)","%"],["Unrealized gain (loss) on derivative contracts","\u200b","\u200b","902","\u200b","\u200b","(492)","\u200b","\u200b","1,394","\u200b","(283.3)","%"],["Total net gain (loss) on derivative contracts","\u200b","$","(2,850)","\u200b","$","473","\u200b","$","(3,323)","\u200b","(702.5)","%"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Average realized crude oil price per BBL","\u200b","$","66.61","\u200b","$","66.71","\u200b","$","(0.10)","\u200b","(0.1)","%"],["Cash effect of oil derivative contracts per BBL","\u200b","\u200b","(6.07)","\u200b","\u200b","0.84","\u200b","\u200b","(6.91)","\u200b","(822.6)","%"],["Crude oil price per Bbl (including impact of realized derivatives)","\u200b","$","60.54","\u200b","$","67.55","\u200b","$","(7.01)","\u200b","(10.4)","%"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Average realized natural gas price per MCF","\u200b","$","2.97","\u200b","$","2.80","\u200b","$","0.17","\u200b","6.1","%"],["Cash effect of natural gas derivative contracts per MCF","\u200b","\u200b","0.10","\u200b","\u200b","0.04","\u200b","\u200b","0.06","\u200b","150","%"],["Natural gas price per Mcf (including impact of realized derivatives)","\u200b","$","3.07","\u200b","$","2.84","\u200b","$","0.23","\u200b","8.1","%"]]
[[/GREPCENT_TABLE]]

​

Interest Expense

Interest expense increased $0.9 million during the fiscal year ended June 30, 2026 compared to fiscal year 2025 primarily due to borrowings drawn on our Senior Secured Credit Facility to finance our SCOOP/STACK Minerals Acquisition in August 2025. Partially offsetting the increase in interest expense is the decrease in our weighted average interest rate on our borrowings to 6.69% for the fiscal year ended June 30, 2026 compared to 7.48% for fiscal year 2025.

Income tax (expense) provision

For the year ended June 30, 2026, we recognized an income tax benefit of $0.7 million on losses before income taxes of $3.1 million compared to an income tax expense of $0.4 million on income before income taxes of $1.9 million for the year ended June 30, 2025. The effective tax rates were 22.8% and 21.2% for the years ended June 30, 2026 and 2025, respectively.

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Critical Accounting Policies and Estimates

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 consolidated financial statements. Our significant accounting policies are included in Note 1, “Summary of Significant Events and Accounting Policies” to our consolidated statements in Item 8. Following is a discussion of our most critical accounting estimates, judgments, and uncertainties that are inherent in the preparation of our consolidated financial statements.

Oil and Natural Gas Properties.   Companies engaged in the production of oil and natural gas are required to follow accounting rules that are unique to the oil and natural gas industry. We apply the full cost accounting method for our oil and natural gas properties as prescribed by SEC Regulation S-X Rule 4-10. Under this method of accounting, the costs of unsuccessful and successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration, and development activities but does not include any costs related to production, general corporate overhead, or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded represent investments in unevaluated properties. We exclude these costs until the property has been evaluated. Costs are transferred to the full cost pool as the properties are evaluated. As of June 30, 2026 and 2025, we had no unevaluated property costs. Oil and natural gas properties include costs that are excluded from depletion and amortization, which represent investments in unproved and unevaluated properties and include non-producing leasehold, geologic and geophysical costs associated with leasehold or drilling interests, and exploration drilling costs.

Estimates of Proved Reserves.    The estimated quantities of proved oil and natural gas reserves have a significant impact on the underlying financial statements. The estimated quantities of proved reserves are used to calculate depletion expense and the estimated future net cash flows associated with those proved reserves is the basis for determining impairment under the quarterly ceiling test calculation. The process of estimating oil and natural gas reserves is very complex and requires significant decisions in the evaluation of all available geologic, geophysical, engineering, and economic data. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information; this includes reservoir performance, additional development activity, new geologic and geophysical data, additional drilling, technological advancements, price changes, and other economic factors. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates prepared by our third-party independent engineers represent the most accurate assessments possible, the subjective decisions and variances in available data for the properties make these estimates generally less precise than other estimates included in our financial statements. Material revisions to reserve estimates and/or significant changes in commodity prices could substantially affect our estimated future net cash flows of our proved reserves. These changes could affect our quarterly ceiling test calculation and could significantly affect our depletion rate. Additionally, a 10% decrease in commodity prices used to determine our proved reserves as of June 30, 2026, while all other factors remained constant, would not have resulted in an impairment of our oil and natural gas properties. Holding all other factors constant, a reduction in our proved reserve estimates at June 30, 2026 of 10% would affect depletion, depreciation, and amortization expense by approximately $0.2 million.

On December 31, 2008, the SEC issued its final rule on the modernization of reporting oil and natural gas reserves. The rule allows consideration of new technologies in evaluating reserves, generally limits the designation of proved reserves to those projects forecasted to be drilled five years from the initial recognition date of such reserves, allows companies to disclose their probable and possible reserves to investors, requires reporting of oil and natural gas reserves using an average price based on the previous 12-month unweighted arithmetic average first-day-of-the-month price rather than year-end prices, revises the disclosure requirements for oil and natural gas operations, and revises accounting for the limitation on capitalized costs for full cost companies.

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Stock-based Compensation.   The fair value, and for certain awards the expected vesting period, of our performance-based awards were determined using a Monte Carlo simulation. This technique uses a geometric Brownian motion model with defined variables and randomly generates values for each variable through multiple trials. Variables include stock price volatility, expected term of the award, the expected risk-free interest rate, and the expected dividend yield of our stock. The risk-free interest rate used is the U.S. Treasury yield for bonds matching the expected term of the award on the date of grant. Vesting of performance-based awards is based on our total common stock return compared to a peer group of other companies in our industry with comparable market capitalizations.

Recent Accounting Pronouncements.   Refer to Note 1, “Summary of Significant Events and Accounting Policies” to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data for discussion of the recent accounting pronouncements issued by the Financial Accounting Standards Board.