EVOLUTION PETROLEUM CORP (EPM)

CIK: 0001006655. SIC: 1311 Crude Petroleum & Natural Gas. Latest 10-K as of: 2025-09-17.

SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1311 Crude Petroleum & Natural Gas

SEC company page: https://www.sec.gov/edgar/browse/?CIK=1006655. Latest filing source: 0001104659-25-090839.

Selected Fundamentals

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2025-09-17. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001006655.json. Derived margins, ratios, and free cash flow are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Free cash flow = operating cash flow - capital expenditures. Missing metrics are omitted rather than fabricated.

Ratios

ROE and ROA use period-end equity/assets. Liabilities / equity uses total liabilities divided by stockholders' equity. Current ratio uses current assets divided by current liabilities when both are reported.

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-13. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001006655.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

Quarterly Charts

Macro Cross-References

• CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
• UNRATE - Unemployment Rate
• FEDFUNDS - Federal Funds Effective Rate
• CES0500000003 - Average Hourly Earnings of All Employees, Total Private
• DFEDTARU - Federal Funds Target Range - Upper Limit
• DFEDTARL - Federal Funds Target Range - Lower Limit
• DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
• DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
• DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
• DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
• T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
• CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
• CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
• CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
• CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
• PCEPI - Personal Consumption Expenditures: Chain-type Price Index
• PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
• PPIACO - Producer Price Index by Commodity: All Commodities
• T10YIE - 10-Year Breakeven Inflation Rate
• U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
• PAYEMS - All Employees, Total Nonfarm
• CIVPART - Labor Force Participation Rate
• EMRATIO - Employment-Population Ratio
• UNEMPLOY - Unemployed
• CE16OV - Employment Level
• ICSA - Initial Claims
• JTSJOL - Job Openings: Total Nonfarm
• JTSQUR - Quits: Total Nonfarm
• GDPC1 - Real Gross Domestic Product
• A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
• INDPRO - Industrial Production: Total Index
• TCU - Capacity Utilization: Total Index
• HOUST - New Privately-Owned Housing Units Started: Total Units
• PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
• RSAFS - Advance Retail Sales: Retail Trade
• PCE - Personal Consumption Expenditures
• DSPIC96 - Real Disposable Personal Income
• PSAVERT - Personal Saving Rate
• M2SL - M2
• BOPGSTB - U.S. International Trade in Goods and Services: Balance
• MSPUS - Median Sales Price of Houses Sold for the United States
• HSN1F - New One Family Houses Sold: United States
• RHORUSQ156N - Homeownership Rate in the United States
• TTLCONS - Total Construction Spending: Total Construction in the United States
• RRVRUSQ156N - Rental Vacancy Rate in the United States
• TOTALSL - Total Consumer Credit Owned and Securitized
• REVOLSL - Revolving Consumer Credit Owned and Securitized
• DRCCLACBS - Delinquency Rate on Credit Card Loans, All Commercial Banks
• GDP - Gross Domestic Product
• GPDI - Gross Private Domestic Investment
• GCE - Government Consumption Expenditures and Gross Investment
• PCEC - Personal Consumption Expenditures
• NETEXP - Net Exports of Goods and Services
• GFDEBTN - Federal Debt: Total Public Debt
• GFDEGDQ188S - Federal Debt: Total Public Debt as Percent of Gross Domestic Product
• FYFSD - Federal Surplus or Deficit
• FGRECPT - Federal Government Current Receipts
• FGEXPND - Federal Government: Current Expenditures
• MANEMP - All Employees, Manufacturing
• USCONS - All Employees, Construction
• USTRADE - All Employees, Retail Trade
• USFIRE - All Employees, Financial Activities
• USGOVT - All Employees, Government
• AWHAETP - Average Weekly Hours of All Employees, Total Private
• DGORDER - Manufacturers' New Orders: Durable Goods
• NEWORDER - Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft
• BUSINV - Total Business Inventories
• EXPGS - Exports of Goods and Services
• IMPGS - Imports of Goods and Services
• IR - Import Price Index (End Use): All Commodities
• PPIFIS - Producer Price Index by Commodity: Final Demand

Latest quarter (10-Q)

Latest 10-Q source: 0001104659-26-060249.

Extracted structurally from real Item 2 body heading to real Item 3/4 boundary. Confidence: high. Filing date: 2026-05-13. Report date: 2026-03-31.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

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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

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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 c

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted from Item 7 to the first post-MD&A boundary after HTML sanitization. Confidence: high. Filing date: 2025-09-17. Report date: 2025-06-30.

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

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 interests in the following areas (as well as small overriding royalty interests in four onshore central Texas wells):

●

Our non-operated 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.

●

Our non-operated interests in the SCOOP and STACK plays, consist of oil and natural gas producing properties in the Anadarko basin, where we hold approximately 2.6% average net working interest and approximately 2.0% average net revenue interests located on approximately 103,700 gross (4,200 net) acres (approximately 97% held by production) across Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties in Oklahoma. The oil and natural gas properties are operated by Continental Resources, Inc., Ovintiv USA Inc. and EOG Resources, Inc. with approximately 40% of wells operated by other operators.

●

Our non-operated interests in the Chaveroo Field consist of a 50% net working interest, with an average associated 41% 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”).

●

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.

●

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 Management.

●

Our non-operated 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 small overriding royalty interests). The approximately 123,800 gross (21,000 net) acres are held by

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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.

●

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.

●

Our non-operated interests in the Delhi Field, a CO2-EOR project, consist of approximately 24% average net working interest, with an associated 19% 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 acres, is located in northeast Louisiana in Franklin, Madison, and Richland Parishes.

Recent Developments

​

Dividend Declaration

​

On September 11, 2025, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable September 30, 2025.

​

Purchase of SCOOP/STACK Minerals

​

On August 4, 2025, we completed the acquisition of certain mineral and royalty interests in the SCOOP/STACK area of Oklahoma from a non-affiliated private seller (the “Minerals Acquisition”) in a cash transaction valued at approximately $17.0 million, subject to customary post-closing adjustments. The Minerals Acquisition has an effective date of May 1, 2025. We funded the purchase price for the 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% located on approximately 5,500 net royalty acres located primarily in Grady and Canadian Counties, Oklahoma.

​

Senior Secured Credit Facility

​

On June 30, 2025, we entered into an amended and restated senior secured reserve-based credit agreement (the “Senior Secured Credit Facility”) with MidFirst Bank, as administrative agent for the lenders party thereto, in an amount up to $200.0 million with an initial borrowing base of $65.0 million maturing on June 30, 2028. Refer to “Liquidity and Capital Resources” below for a further discussion.

​

Purchase of Non-operated Oil and Natural Gas Assets

​

On April 14, 2025, we closed the acquisition of non-operating working interests in certain long-life oil and natural gas wells located primarily in Lea, Eddy and Chaves Counties, New Mexico and Stephens County, Texas (the “TexMex Acquisition”) from a private seller. The total purchase price for the TexMex Acquisition was approximately $9.0 million before customary post-closing adjustments, with an effective date of February 1, 2025. We funded the purchase price for the TexMex Acquisition with a combination of cash on hand and borrowings under our Senior Secured Credit Facility. The TexMex Acquisition includes an average working interest of 42% and an average revenue interest of 35% in approximately 600 wells.

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

​

On October 21, 2024, we entered into an ATM equity Sales Agreement (the “ATM Sales Agreement”) with Roth Capital Partners, LLC (the “Lead Agent”), Northland Securities Inc., and A.G.P./Alliance Global Partners pursuant to which we

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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. For the year ended June 30, 2025, we sold a total of approximately 0.7 million shares of our common stock under the ATM Sales Agreement for net proceeds of approximately $3.5 million, after deducting $0.3 million in offering costs. We intend to use the net proceeds from any sales of common stock for general corporate purposes, including to repay outstanding indebtedness.  

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Proved Reserves

The following table is a summary of our proved reserves as of June 30, 2025 and 2024:

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Proved Reserves

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2025

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2024

​

Change

Proved Reserves MMBOE

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​

27.1

​

​

​

31.8

​

​

(14.8)

%

% Developed

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​

83.7

%

​

​

75.6

%

​

8.1

%

Liquids %

​

​

62.2

%

​

​

59.1

%

​

3.1

%

Standardized Measure ($MM)

​

$

155.2

​

​

$

166.6

​

​

(6.8)

%

​

Proved oil equivalent reserves as of June 30, 2025 were 27.1 MMBOE, a 4.7 MMBOE, or 14.8%, decrease from the previous year of 31.8 MMBOE. The net decrease in total proved reserves was primarily due to net negative revisions of 6.0 MMBOE and production roll-off of 2.6 MMBOE. These decreases were partially offset by 3.0 MMBOE of proved reserves purchased in the TexMex Acquisition as well as extensions of 0.9 MMBOE primarily at Chaveroo Field and SCOOP/STACK. Approximately 1.6 MMBOE of downward revisions were in our oil reserves and 4.4 MMBOE of downward revisions were in our natural gas and NGL reserves. Proved oil reserves declined primarily due to a decrease in the SEC trailing 12-month oil price of 10.4% from the prior fiscal year and drop-off of Williston Basin PUDs due to timing of future drilling plans. Natural gas and natural gas liquids reserves decreased due to a combination of lower price differentials received, specifically at Jonah Field, an increase in lease operating costs at our Barnett Shale properties, and drop-off of the Williston Basin PUDs due to timing of future drilling plans. These metrics impacted the late-in-life economic limits for oil, natural gas, and NGL production.

The Standardized Measure for proved reserves decreased 6.8% to $155.2 million, primarily due to volumes produced and sold and our overall downward revisions in proved reserves as discussed above. Oil prices decreased 10.4% from the prior year when oil was $79.45 per barrel compared to $71.20 per barrel at June 30, 2025. While the SEC price for natural gas increased 23.7% from $2.32 per MMBtu of natural gas at June 30, 2024 to $2.87 per MMBtu of natural gas at June 30, 2025, certain changes in other metrics such as lower price differentials caused our natural gas and natural gas liquids reserves to decrease, as stated above. Our proved reserves consist of 45% oil, 38% natural gas, and 17% NGLs; 83.7% 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 and armed conflicts (including between Russia and Ukraine and in the Middle East between Israel and Gaza), 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. 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. Lower oil and natural gas prices not only decrease our revenues, but an extended decline in oil or natural gas prices may affect planned capital

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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.

​

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 recent years, the Federal Reserve took actions to raise interest rates in an attempt to tame inflation and slow the economy, which has contributed to volatility in markets. 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.

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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, and any related significant declines in crude oil, natural gas, and NGL prices could lead to proved property impairments in the future. Future impairments of proved properties are difficult to predict, especially in a volatile price environment.

Liquidity and Capital Resources

As of June 30, 2025, we had $2.5 million in cash and cash equivalents and $37.5 million outstanding borrowings on our Senior Secured Credit Facility compared to $6.4 million in cash and cash equivalents and $39.5 million outstanding borrowings on our Senior Secured Credit Facility at June 30, 2024. Our primary sources of liquidity and capital resources during the year ended June 30, 2025 were cash provided by operations and net proceeds from the ATM Sales agreement. Our primary uses of liquidity and capital resources for the year ended June 30, 2025 were cash dividend payments to our common stockholders, our TexMex Acquisition, net repayments of borrowings under our Senior Secured Credit Facility and development capital expenditures, primarily at Chaveroo Field and SCOOP/STACK. As of June 30, 2025, working capital was a deficit of $4.0 million. As of June 30, 2024, working capital was $5.9 million.

As noted above, on June 30, 2025, we entered into a syndicated amended and restated senior secured reserve-based credit agreement (the “Senior Secured Credit Facility”) with MidFirst Bank, as administrative agent for the lenders party thereto. The Senior Secured Credit Facility has a maximum capacity of $200.0 million subject to a borrowing base determined by the lenders based on 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 June 30, 2025, we had $37.5 million of indebtedness outstanding and availability of $27.5 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, 2025 and 2024, the weighted average interest on our borrowings were 7.48% and 8.12%, respectively. The Senior Secured Credit Facility contains covenants requiring the maintenance of (i) a total leverage ratio of not more than 3.00 to 1.00, (ii) a current ratio of not less than 1.00 to 1.00, and (iii) a consolidated tangible net worth of not less than $40.0 million, each as defined in the Senior Secured Credit Facility. In addition, the Senior Secured Credit Facility contains hedging requirements that apply when utilization is greater than 25% of (x) the Margined Collateral Value, as defined under the Senior Secured Credit Facility, at any time when the leverage ratio is less than 2.25 to 1.00, or (y) the borrowing base, at any time when the leverage ratio is greater than or equal to 2.25 to 1.00. It also contains other customary affirmative and negative covenants, and events of default. As of June 30, 2025, we were in compliance with all covenants under the Senior Secured Credit Facility.

The Senior Secured Credit Facility requires for redeterminations of the borrowing base to occur semi-annually. At each redetermination, the Margined Collateral Value is updated based on the estimated value of our oil and natural gas

34

Table of Contents

properties, which includes our proved developed reserves, proved undeveloped reserves, and other relevant factors consistent with customary oil and natural gas lending criteria. On August 29, 2025, we entered into an 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 volumes from proved developed producing reserves will be combined on a barrels of oil equivalent (“BOE”) basis to determine compliance with the hedging covenant.

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

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 $27.5 million as of June 30, 2025. As stated above in “Recent Developments,” on August 4, 2025, we purchased mineral and royalty interests in the SCOOP/STACK area of Oklahoma for approximately $17.0 million. We funded the acquisition with borrowings of $15.0 million on our Senior Secured Credit Facility and cash on hand. On August 5, 2025, we issued an $0.8 million letter of credit agreement to Enterprise Products Operating, LLC, in connection with our gathering and processing agreements at Jonah Field, in exchange for the return of our cash collateral that had been previously provided. This additional borrowing and letter of credit reduced our remaining availability to $11.7 million subsequent to our fiscal year end. 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 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. For the year ended June 30, 2025, we sold a total of approximately 0.7 million shares of our common stock under the ATM Sales Agreement for net proceeds of approximately $3.5 million, after deducting $0.3 million in offering costs.

​

Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 47 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, as appropriate. On September 11, 2025, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on September 22, 2025 and payable on September 30, 2025.

On September 8, 2022, our Board of Directors approved a share repurchase program, under which we were authorized to repurchase up to $25.0 million of our common stock in the open market through December 31, 2024. As we continue to focus on our goal of maximizing total shareholder return, the Board of Directors along with the management team believe that a share repurchase program may be complimentary to the existing dividend policy and could be a tax efficient means to further improve shareholder return. In fiscal year 2025, we did not repurchase any shares under the program. In fiscal year 2024, we entered into a Rule 10b5-1 plan that authorized a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan was effective until June 30, 2024 and had a maximum authorized amount of $0.8 million over that period. During the fiscal year ended June 30, 2024, approximately 0.1 million shares of the Company’s common stock were repurchased under the plan at a cost of approximately $0.8 million, including incremental direct transaction costs. We funded repurchases from working capital and cash provided by operating activities. These shares were subsequently cancelled. We may enter into additional share repurchase programs in the future as well as Rule 10b5-1 plans, the terms of which will be approved by the Board of Directors.

​

35

Table of Contents

Capital Expenditures

For the year ended June 30, 2025, we incurred $13.2 million on development capital expenditures. A majority of our spending occurred at the Chaveroo Field where we participated in drilling and completion of four gross wells, and at SCOOP/STACK where our operators have brought 13 gross (0.14 net) wells online during the fiscal year.

Based on discussions with our operators, we expect capital workover projects to continue in most of our fields. 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 any potential acquisitions. Our expected capital expenditures for the next 12 months include bringing approximately five gross wells online 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 expect to have drilling permits in hand for the next round of six wells before the end of the fiscal third quarter 2026 and the final decision by us and our partner as to timing for spudding these wells will be made based on oil prices and completed well costs at that time.

As of June 30, 2025, our PUD reserves included 4.4 MMBOE of reserves and approximately $75.1 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 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, 2025 were $71.20 per barrel of oil, $2.87 per MMBtu of natural gas and $25.24 per barrel of NGLs. As of June 30, 2025, our capitalized costs of oil and natural gas properties 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, 2025 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. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required in the future. Additionally, a 10% reduction in respective commodity prices at June 30, 2025, while all other factors remained constant, would not have generated an impairment.

​

Overview of Cash Flow Activities

​

​

​

​

​

​

​

​

​

​

​

​

Years Ended June 30, 

​

​

​

​

2025

2024

Change

Cash flows provided by operating activities

​

$

33,052

​

$

22,729

​

$

10,323

Cash flows used in investing activities

​

​

(21,642)

​

​

(49,633)

​

​

27,991

Cash flows provided by (used in) financing activities

​

​

(15,349)

​

​

22,316

​

​

(37,665)

Net decrease in cash and cash equivalents

​

$

(3,939)

​

$

(4,588)

​

$

649

​

Cash provided by operating activities increased $10.3 million during the fiscal year ended June 30, 2025 compared to fiscal year ended June 30, 2024 primarily due to changes in the timing of our working capital. Cash flows provided by operating activities before changes in working capital for the year ended June 30, 2025 decreased $1.8 million compared to the year ended June 30, 2024, primarily due to increases in our lease operating costs and interest expenses in the current year partially offset by realized gains on derivative contracts in the current year of $1.0 million compared to

36

Table of Contents

realized losses on derivative contracts in the prior year of $0.4 million. Refer to “Results of Operations” below for further information.

Cash used in investing activities for the year ended June 30, 2025 decreased $28.0 million from the prior year primarily due to the acquisition of our SCOOP/STACK properties in February 2024. In the prior year, net cash spent on acquisitions was $38.7 million, whereas in the current year, net cash spent on acquisitions was $9.0 million. In addition, in fiscal year 2025, we spent $12.6 million on development capital expenditures as compared to $10.9 million in the prior year. In the current fiscal year capital expenditures included drilling and completing four gross (2.0 net) Chaveroo wells and thirteen gross (0.14 net) SCOOP/STACK wells. In the prior year, the Company participated in drilling and completing three gross (1.5 net) Chaveroo wells and to a lesser extent, drilling and completion expenditures at Delhi Field and SCOOP/STACK.

Net cash flows used in financing activities for the year ended June 30, 2025 were $15.3 million compared to net cash flows provided by financing activities of $22.3 million for the year ended June 30, 2024. In the current year period, we paid $16.3 million in cash dividends to our common stockholders, repaid $2.0 million of net borrowings under our Senior Secured Credit Facility, and received net proceeds from the sale of common stock under the ATM Sales Agreement of approximately $3.5 million, after deducting $0.3 million in offering costs. In the prior year period, we received net borrowings of $39.5 million under our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions, paid $16.0 million in cash dividends to our common stockholders together with $0.8 million paid to repurchase shares of common stock under our share repurchase plan.

​

37

Table of Contents

Results of Operations

Years Ended June 30, 2025 and 2024

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

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Years Ended June 30, 

​

​

​

​

​

​

(in thousands, except per unit and per BOE amounts)

2025

2024

Variance

Variance %

Net income (loss)

​

$

1,473

​

$

4,080

​

$

(2,607)

​

(63.9)

%

Revenues:

​

​

​

​

​

​

​

​

​

​

​

​

Crude oil

​

​

51,102

​

​

53,446

​

​

(2,344)

​

(4.4)

%

Natural gas

​

​

23,516

​

​

21,525

​

​

1,991

​

9.2

%

Natural gas liquids

​

​

11,222

​

​

10,906

​

​

316

​

2.9

%

Total revenues

​

​

85,840

​

​

85,877

​

​

(37)

​

(0.0)

%

Operating costs:

​

​

​

​

​

​

​

​

​

​

​

​

Lease operating costs:

​

​

​

​

​

​

​

​

​

​

​

​

Ad valorem and production taxes

​

​

5,709

​

​

5,285

​

​

424

​

8.0

%

Gathering, transportation, and other costs

​

​

11,357

​

​

9,656

​

​

1,701

​

17.6

%

Other lease operating costs

​

​

32,272

​

​

33,332

​

​

(1,060)

​

(3.2)

%

Depletion, depreciation, and accretion:

​

​

​

​

​

​

​

​

​

​

​

​

Depletion of full cost proved oil and natural gas properties

​

​

20,374

​

​

18,605

​

​

1,769

​

9.5

%

Accretion of asset retirement obligations

​

​

1,619

​

​

1,457

​

​

162

​

11.1

%

General and administrative expenses:

​

​

​

​

​

​

​

​

​

​

​

​

General and administrative

​

​

7,852

​

​

7,499

​

​

353

​

4.7

%

Stock-based compensation

​

​

2,482

​

​

2,137

​

​

345

​

16.1

%

Other income (expense):

​

​

​

​

​

​

​

​

​

​

​

​

Net gain (loss) on derivative contracts

​

​

473

​

​

(1,292)

​

​

1,765

​

(136.6)

%

Interest and other income

​

​

191

​

​

342

​

​

(151)

​

(44.2)

%

Interest expense

​

​

(2,970)

​

​

(1,459)

​

​

(1,511)

​

103.6

%

Income tax (expense) benefit

​

​

(396)

​

​

(1,417)

​

​

1,021

​

(72.1)

%

​

​

​

​

​

​

​

​

​

​

​

​

​

Production:

​

​

​

​

​

​

​

​

​

​

​

​

Crude oil (MBBL)

​

​

766

​

​

709

​

​

57

​

8.0

%

Natural gas (MMCF)

​

​

8,409

​

​

8,243

​

​

166

​

2.0

%

Natural gas liquids (MBBL)

​

​

414

​

​

402

​

​

12

​

3.0

%

Equivalent (MBOE)(1)

​

​

2,582

​

​

2,485

​

​

97

​

3.9

%

Average daily production (BOEPD)(1)

​

​

7,074

​

​

6,790

​

​

284

​

4.2

%

​

​

​

​

​

​

​

​

​

​

​

​

​

Average price per unit(2):

​

​

​

​

​

​

​

​

​

​

​

​

Crude oil (BBL)

​

$

66.71

​

$

75.38

​

$

(8.67)

​

(11.5)

%

Natural gas (MCF)

​

​

2.80

​

​

2.61

​

​

0.19

​

7.3

%

Natural Gas Liquids (BBL)

​

​

27.11

​

​

27.13

​

​

(0.02)

​

(0.1)

%

Equivalent (BOE)(1)

​

​

33.25

​

​

34.56

​

​

(1.31)

​

(3.8)

%

​

​

​

​

​

​

​

​

​

​

​

​

​

Average cost per unit:

​

​

​

​

​

​

​

​

​

​

​

​

Operating costs:

​

​

​

​

​

​

​

​

​

​

​

​

Lease operating costs:

​

​

​

​

​

​

​

​

​

​

​

​

Ad valorem and production taxes

​

$

2.21

​

$

2.13

​

$

0.08

​

3.8

%

Gathering, transportation, and other costs

​

​

4.40

​

​

3.89

​

​

0.51

​

13.1

%

Other lease operating costs

​

​

12.50

​

​

13.41

​

​

(0.91)

​

(6.8)

%

Depletion of full cost proved oil and natural gas properties

​

​

7.89

​

​

7.49

​

​

0.40

​

5.3

%

General and administrative expenses:

​

​

​

​

​

​

​

​

​

​

​

​

General and administrative

​

​

3.04

​

​

3.02

​

​

0.02

​

0.7

%

Stock-based compensation

​

​

0.96

​

​

0.86

​

​

0.10

​

11.6

%

(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.

​

​

38

Table of Contents

Revenues

Crude oil, natural gas and NGL revenues were $85.8 million and $85.9 million for the fiscal years ended June 30, 2025 and 2024, respectively. The decrease in revenues is primarily due to the decrease in our average realized price per BOE partially offset by an increase in our sales volumes primarily as a result of our recent acquisitions. Our average realized commodity price (excluding the impact of derivative contracts) decreased approximately $1.31 per BOE, or 3.8%, for the fiscal year ended June 30, 2025 compared to June 30, 2024. 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. While crude oil and NGL prices decreased 11.5% and 0.1% from the prior fiscal year respectively, our average realized commodity prices, realized natural gas prices increased 7.3% from the prior fiscal year predominately due to favorable pricing recognized from our SCOOP/STACK properties. Average daily equivalent production increased 4.2% from 6,790 BOEPD to 7,074 BOEPD in the current fiscal year as a result of additional production from newly drilled wells at Chaveroo Field, the Tex Mex Acquisition in April 2025, and drilling activities that are ongoing at SCOOP/STACK since the prior year end. The increase in production was partially offset by natural production declines in our other fields.

​

Lease Operating Costs

Ad valorem and production taxes were $5.7 million and $5.3 million for the years ended June 30, 2025 and 2024, respectively. The increase in ad valorem and production taxes is primarily due to our SCOOP/STACK Acquisitions since the prior year period. On a per unit basis, ad valorem and production taxes were $2.21 per BOE and $2.13 per BOE for the years ended June 30, 2025 and 2024, respectively.

Gathering, transportation and other costs were $11.4 million for the year ended June 30, 2025 compared to $9.7 million for the year ended June 30, 2024. These costs are gathering, transportation and processing fees we incur primarily for our natural gas producing properties. The increase is primarily due to the SCOOP/STACK Acquisitions in February 2024 which increased gathering, transportation and other costs by $1.2 million over the prior year period. On a per unit basis, gathering, transportation and other costs were $4.40 per BOE and $3.89 per BOE for the years ended June 30, 2025 and 2024, respectively.

Other lease operating costs decreased $1.1 million, or 3.2%, compared to the prior fiscal year primarily due to a $1.9 million credit from the operator of one of our Barnett Shale properties due to a joint venture audit combined with the cessation of CO2 purchases at Delhi late in the third fiscal quarter. CO2 purchases resumed in late October of 2024 following the pipeline shutdown for maintenance and repairs early in 2024. Consequently, we had net purchases of $2.6 million of CO2 for the year ended June 30, 2025 compared to net purchases of $4.2 million in the prior year period. Partially offsetting the reduction in CO2 purchases were cost increases due to our acquisitions of TexMex in April 2025 and SCOOP/STACK in February 2024, which collectively increased other lease operating costs by $2.3 million over the prior year period. On a per unit basis, other lease operating costs decreased to $12.50 per BOE in the current year from $13.41 per BOE in the prior year, primarily due to an overall increase in production.

Depletion of Full Cost Proved Oil and Natural Gas Properties

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

General and Administrative Expenses

General and administrative expenses for the fiscal year ended June 30, 2025 increased $0.4 million, or 4.7%, to $7.9 million compared to $7.5 million for the fiscal year ended June 30, 2024. The increase primarily relates higher salary and compensation expense adjustments for existing employees. On a per unit basis, general and administrative expenses were $3.04 per BOE and $3.02 per BOE for the years ended June 30, 2025 and 2024, respectively.

39

Table of Contents

Stock-based Compensation Expenses

Stock-based compensation increased $0.3 million to $2.5 million for the year ended June 30, 2025 compared to $2.1 million the prior period. The increase is due to new awards granted during the current 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 Acquisitions in February 2024 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. The increase in the forward curve for future natural gas prices, as of June 30, 2025 as compared to June 30, 2024, resulted in a net unrealized loss on the mark-to-market of our hedges for the year ended June 30, 2025. As of June 30, 2025, we had a $2.0 million derivative asset, $1.8 million of which was classified as current, and a $3.4 million derivative liability, $1.6 million of which was classified as current.

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Years Ended June 30, 

​

​

​

​

​

​

(in thousands, except per unit and per BOE amounts)

2025

2024

Variance

Variance %

Realized gain (loss) on derivative contracts

​

$

965

​

$

(399)

​

$

1,364

​

(341.9)

%

Unrealized gain (loss) on derivative contracts

​

​

(492)

​

​

(893)

​

​

401

​

(44.9)

%

Total net gain (loss) on derivative contracts

​

$

473

​

$

(1,292)

​

$

1,765

​

(136.6)

%

​

​

​

​

​

​

​

​

​

​

​

​

​

Average realized crude oil price per BBL

​

$

66.71

​

$

75.38

​

$

(8.67)

​

(11.5)

%

Cash effect of oil derivative contracts per BBL

​

​

0.84

​

​

(0.56)

​

​

1.40

​

(250.0)

%

Crude oil price per Bbl (including impact of realized derivatives)

​

$

67.55

​

$

74.82

​

$

(7.27)

​

(9.7)

%

​

​

​

​

​

​

​

​

​

​

​

​

​

Average realized natural gas price per MCF

​

$

2.80

​

$

2.61

​

$

0.19

​

7.3

%

Cash effect of natural gas derivative contracts per MCF

​

​

0.04

​

​

—

​

​

0.04

​

—

%

Natural gas price per Mcf (including impact of realized derivatives)

​

$

2.84

​

$

2.61

​

$

0.23

​

8.8

%

​

Interest Expense

Interest expense increased $1.5 million during the fiscal year ended June 30, 2025 compared to fiscal year 2024 primarily due to borrowings drawn on our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions in February 2024. Partially offsetting the increase in interest expense is the decrease in our weighted average interest rate on our borrowings to 7.48% for the fiscal year ended June 30, 2025 compared to 8.12% for fiscal year 2024.

Income tax (expense) provision

For the year ended June 30, 2025, we recognized income tax expense of $0.4 million on income before income taxes of $1.9 million compared to an income tax expense of $1.4 million on income before income taxes of $5.5 million for the year ended June 30, 2024. The effective tax rates were 21.2% and 25.8% for the years ended June 30, 2025 and 2024, respectively. The decrease in the effective tax rate from the prior year period is due to federal tax credits on marginal natural gas wells for the calendar year 2024 and 2025.

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

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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, 2025 and 2024, 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, 2025, 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, 2025 of 10% would affect depletion, depreciation, and amortization expense by approximately $0.6 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.

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

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group of other companies in our industry with comparable market capitalizations and, for certain awards, our share price attaining a set target.

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.