Evolution Petroleum Corp: Form 10-Q for the period ended Mar 31, 2025

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, 2025, our third quarter of fiscal year 2025.

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

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 of non-operated interests in the SCOOP and STACK plays of the Anadarko Basin located in central Oklahoma; the Chaveroo Field in Chaves and Roosevelt Counties of New Mexico; Jonah Field in Sublette County, Wyoming; the Williston Basin in North Dakota; the Barnett Shale located in North Texas; the Hamilton Dome Field located in Hot Springs County, Wyoming; the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana; and small overriding royalty interests in four onshore central Texas wells.

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 or 4,200 net acres (approximately 96% 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. Production from our SCOOP/STACK properties for the nine months ended March 31, 2025 is comprised of 50% natural gas, 34% crude oil, and 16% NGLs.

Our non-operated interests in the Chaveroo Field consist of a 50% net working interest, with an average associated 41% revenue interest, in approximately 3,200 gross or 1,600 net acres all held by production, associated with five 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, 2025 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 or 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, 2025 is comprised of 90% natural gas, 5% crude oil, and 5% NGLs.

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 141,400 gross or 42,200 net acres (approximately 95% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota. The properties are operated by Foundation Energy Management. Production from our Williston Basin properties for the nine months ended March 31, 2025 is comprised of 77% crude oil, 13% NGL, and 10% natural gas.

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 or 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, 2025 is comprised of 74% natural gas, 25% 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 approximately 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, 2025 is comprised of 100% crude oil.

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 approximately 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, 2025 is comprised of 77% crude oil and 23% NGL.

During the nine months ended March 31, 2025, crude oil, natural gas and NGL production increased 5% compared to the year-ago period due to our recent acquisitions and development drilling activities since the year-ago period. Our crude oil, natural gas and NGL revenues remained flat over the same period despite our increase in production volumes due to declines in commodity prices. Our lease operating costs for the nine months ended March 31, 2025 have increased 3% in total, but decreased $0.45 per BOE due to increased production, compared to the year-ago period.

Of particular note, the Company’s financial results were adversely impacted by net unrealized losses on derivative contracts of $3.9 million and $3.4 million for the three and nine months ended March 31, 2025. The unrealized losses on derivative contracts are non-cash charges incurred at a point in time, due to the mark-to-market valuation of our hedges for future periods based on current forward price curves. The mark-to-market is also reflected as derivative contract assets and liabilities on the Company’s unaudited condensed consolidated balance sheets. Continued volatility in commodity markets will also cause volatility in the valuation of our derivative contracts. Financial hedges are a requirement under our Senior Secured Credit Facility and help establish commodity price floors, contributing to stable cash flows when the derivative contracts are settled, thereby supporting our dividend strategy. See below for a further discussion around our results of operations and cash flow activities.

Recent Developments

Dividend Declaration

On May 12, 2025, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable June 30, 2025.

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. In March 2025, we made a deposit of $1.8 million with the seller to acquire the assets. 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 balance of the purchase price for the TexMex Acquisition in April 2025 with a combination of cash on hand and borrowings under our Senior Secured Credit Facility.

The TexMex Acquisition includes an average working interest of 42.2% and an average revenue interest of 35.2% in approximately 600 wells. The current net daily production of the acquired assets is approximately 440 BOEPD, based on the average for the three months ended March 31, 2025, with a commodity split of 60% oil and 40% natural gas.

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 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. During the nine months ended March 31, 2025, we sold a total of approximately 0.6 million shares of our common stock under the ATM Sales Agreement for net proceeds of approximately $3.1 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 redeem or repay outstanding indebtedness. We are not obligated to sell any shares of common stock in the future.

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 and natural gas 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 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, as well as the dividend rate determined by the Board of Directors each quarter.

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.

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 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 March 31, 2025, we had $5.6 million in cash and cash equivalents and $35.5 million outstanding borrowings on our Senior Secured Credit Facility compared to $6.4 million in cash and cash equivalents and $39.5 million borrowings outstanding on our Senior Secured Credit Facility at June 30, 2024. Our primary sources of liquidity and capital resources during the nine months ended March 31, 2025 were cash provided by operations and net proceeds from the ATM Sales Agreement. Our primary uses of liquidity and capital resources for the nine months ended March 31, 2025 were cash dividend payments to our common stockholders, repayments of borrowings under our Senior Secured Credit Facility, deposit made for the TexMex Acquisition, and development capital expenditures. As of March 31, 2025, working capital was a deficit of $2.7 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 well as current payables associated with our active drilling in the Chaveroo Field. As of June 30, 2024, working capital was $5.9 million.

The Senior Secured Credit Facility has a maximum capacity of $50.0 million subject to a borrowing base determined by the lender based on the value of our oil and natural gas properties. The Senior Secured Credit Facility has a current borrowing base of $50.0 million, with $35.5 million drawn as of March 31, 2025. The Senior Secured Credit Facility is secured by substantially all of our oil and natural gas properties and matures on April 9, 2026. We have received approval from our lender, MidFirst Bank, to extend the maturity of our existing Senior Secured Credit Facility to April 2028 and increase their total commitments from $50.0 million to $55.0 million. Also, we expect to receive $10.0 million in additional commitments from a new lender, Prism Bank, bringing our total commitments to $65.0 million. We expect all other terms to remain substantially the same and anticipate closing on the facility during our fiscal fourth quarter.

Borrowings bear interest, at our option, at either the SOFR plus 2.80% or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%. For the nine months ended March 31, 2025 and 2024, the weighted average interest on our borrowings was 7.59% and 8.13%, 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. It also contains other customary affirmative and negative covenants, including a hedging covenant discussed below, and events of default. As of March 31, 2025, we were in compliance with all covenants under the Senior Secured Credit Facility.

The Senior Secured Credit Facility contains hedging requirements that apply when there is 25% or more utilization of the Margined Collateral Value, as defined under the Senior Secured Credit Facility, to the extent it exceeds the borrowing base then in effect. The Required Hedging Percentage, as defined in the Eighth Amendment to the Senior Secured Credit Facility dated November 9, 2021, provides for a tiered approach for adding hedges based on the utilization of the facility. The Senior Secured Credit Facility requires for redeterminations of the borrowing base to occur semi-annually. At each redetermination, the Margined Collateral Value is updated based on the estimated value of our oil and natural gas properties, which includes our proved developed reserves, proved undeveloped reserves, and other relevant factors consistent with customary oil and natural gas lending criteria. On March 7, 2025, in conjunction with the spring redetermination, we entered into a letter agreement with MidFirst Bank, which allows us the option to hedge 72% of expected natural gas production rather than hedging 25% of expected crude oil production in each month for the calendar year ending December 31, 2026, as long as we remain in the 25% required hedging tier. As of March 31, 2025, we were in compliance with the hedging requirements under the Senior Secured Credit Facility.

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, existing working capital 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 $14.5 million as of March 31, 2025. 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. During the nine months ended March 31, 2025, we sold a total of approximately 0.6 million shares of our common stock under the ATM Sales Agreement for net proceeds of approximately $3.1 million, after deducting $0.3 million in offering costs; however, we are not obligated to sell any shares of common stock in the future.

Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 46 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. Periodically, the Board of Directors reviews the dividend level, taking into account dividend stability, historical cash flow performance, financial strength of the Company, and future outlook. On May 12, 2025, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on June 13, 2025 and payable on June 30, 2025.

Capital Expenditures

During the nine months ending March 31, 2025, we incurred $8.8 million on development capital expenditures. A majority of our spending occurred at Chaveroo Field, where we are actively participating in four gross drilling locations 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 throughout the remainder of the year as well as further drilling at SCOOP/STACK.

Overall, for fiscal year 2025, we expect budgeted capital expenditures to be in the range of $12.5 million to $14.5 million, which excludes any potential acquisitions. Our expected capital expenditures for fiscal year 2025 include the 13 gross (0.14 net) wells brought online at SCOOP/STACK during the first nine months of the fiscal year, discussed above, with an additional five gross (0.02 net) wells in progress. It also includes the drilling and completion of four gross (1.64 net) wells at Chaveroo Field for development block two, which began production at the end of April 2025.

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 March 31, 2025 were $75.33 per barrel of oil, $2.45 per MMBtu of natural gas and $22.38 per barrel of NGLs. As of March 31, 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 March 31, 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 test results in future quarters. While using the crude oil and natural gas price for April 1, 2025 of $71.61 per barrel and $4.11 per MMBtu and May 1, 2025 of $59.24 per barrel and $3.33 per MMbtu, and holding the May prices constant for one month to create a trailing 12-month period of average prices (which is more reflective of recent price trends) would not generate an impairment under our ceiling test limitation, we cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required in the future.

Overview of Cash Flow Activities

Cash provided by operating activities for the nine months ended March 31, 2025 increased $7.9 million compared to the nine months ended March 31, 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 nine months ended March 31, 2025 decreased $3.5 million compared to the nine months ended March 31, 2024 primarily due to increases in our lease operating costs and interest expense for the comparable periods. Refer to “Results of Operations” below for further information.

Cash used in investing activities for the nine months ended March 31, 2025 decreased $42.1 million compared to the nine months ended March 31, 2024 primarily due to the SCOOP/STACK Acquisitions in February 2024 together with the timing of drilling and completing our Chaveroo development block one in the prior year as compared to this year, partially offset by the deposit we made for the TexMex Acquisition in the current year.

Net cash flows used in financing activities for the nine months ended March 31, 2025 were $13.4 million compared to net cash flows provided by financing activities of $29.4 million for the nine months ended March 31, 2024. For the nine months ended, March 31, 2025, we paid $12.2 million in cash dividends to our common stockholders, repaid $4.0 million of borrowings under our Senior Secured Credit Facility, and received net proceeds from the sale of common stock under the ATM Sales Agreement of approximately $3.1 million, after deducting $0.3 million in offering costs. For the nine months ended March 31, 2024, we borrowed $42.5 million under our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions which was partially offset by $12.0 million in cash dividends to our common stockholders together with $0.8 million paid to repurchase shares of our common stock under our share repurchase plan.

Results of Operations

Three Months Ended December 31, 2024 and 2023

We reported a net loss of $2.2 million and net income of $0.3 million for the three months ended March 31, 2025 and 2024, respectively. The following table summarizes the comparison of financial information for the periods presented:

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

(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.

Revenues

Crude oil, natural gas and NGL revenues were $22.6 million and $23.0 million for the three months ended March 31, 2025 and 2024, respectively. The decrease in revenues is due to a decrease in production volumes partially offset by an increase in our average realized price per BOE. Average daily equivalent production decreased 7.5% from 7,209 BOEPD in the prior year quarter to 6,667 BOEPD in the current quarter primarily due to planned maintenance at the central facility and NGL plant downtime at Delhi Field, January winter weather impacts at Barnett Shale as well as natural production declines. These production decreases were offset by additional production from our SCOOP/STACK Acquisitions in February 2024 which contributed for a full quarter in fiscal 2025. Our average realized commodity price (excluding the impact of derivative contracts) for the three months ended March 31, 2025 increased approximately $2.50 per BOE, or 7.1%, over the prior year quarter. This increase was primarily due to the 39.7% increase in realized natural gas prices and the 27.8% increase in realized NGL prices partially offset by the 6.4% decrease in crude oil prices from the year-ago quarter.

Lease Operating Costs

Gathering, transportation and other costs were $2.9 million for the three months ended March 31, 2025 compared to $2.5 million for the three months ended March 31, 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 $0.3 million over the prior year quarter. On a per unit basis, gathering transportation and other costs were $4.86 per BOE and $3.85 per BOE for the three months ended March 31, 2025 and 2024, respectively.

Other lease operating costs were $9.0 million for the three months ended March 31, 2025 compared to $8.6 million for the three months ended March 31, 2024. Other lease operating costs increased primarily due to increased CO2 purchases at Delhi. CO2 purchases resumed in late October of 2024 after having been suspended in February 2024. We had net purchases of $1.5 million in CO2 for the three months ended March 31, 2025 compared to net purchases of $1.0 million in the year-ago quarter. In addition, the SCOOP/STACK Acquisitions in February 2024 increased other lease operating costs by $0.1 million over the prior year quarter. On a per unit basis, other lease operating costs were $15.00 per BOE and $13.17 per BOE for the three months ended March 31, 2025 and 2024, respectively.

Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense decreased $0.9 million or 16.7% from $5.5 million to $4.6 million for the three months ended March 31, 2025 primarily due to a decrease in the depletion rate. On a per unit basis, depletion expense was $7.68 per BOE and $8.43 per BOE for the three months ended March 31, 2025 and 2024, respectively. The depletion rate of our unit of production calculation decreased due to a decrease in our depletable base.

General and Administrative Expenses

General and administrative expenses for the three months ended March 31, 2025 and 2024 were each $1.9 million. On a per unit basis, general and administrative expenses were $3.22 per BOE and $2.85 per BOE for the three months ended March 31, 2025 and 2024, respectively. The increase on a per unit basis is primarily the result of the decrease in production for the current year quarter.

Stock-based Compensation Expense

Stock-based compensation expense for the three months ended March 31, 2025 increased $0.1 million to $0.6 million compared to $0.5 million for the year-ago quarter. The increase is associated with new awards granted since the year-ago quarter.

Net Gain (Loss) on Derivative Contracts

We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. Financial hedges are a requirement under our Senior Secured Credit Facility and help establish commodity price floors, contributing to stable cash flows when derivative contracts are settled. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the unaudited condensed consolidated statements of operations. The amounts recorded on the unaudited condensed consolidated statements of operations related to derivative contracts represent the (i) gains (losses) related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) gains (losses) on settlements of derivative contracts for positions that have settled or been realized. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized gains (losses) on our average realized prices for the periods presented. As a result of our 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 forward commodity prices since the prior quarter, particularly for natural gas, resulted in a net unrealized loss for the mark-to-market of our hedges for the three months ended March 31, 2025. As of March 31, 2025, we had $0.9 million derivative assets, $0.8 million of which was classified as current, and $5.2 million derivative liabilities, $3.5 million of which was classified as current. Subsequent to the end of the quarter through May 2025, we have seen increased volatility in the crude oil and natural gas commodity markets and we expect to see continued volatility in the fair value of our derivative contracts.

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

Interest Expense

Interest expense increased $0.2 million for the three months ended March 31, 2025 compared to the prior year period primarily due to borrowings drawn on our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions in February 2024.

Income Tax (Expense) Benefit

For the three months ended March 31, 2025, we recognized income tax benefit of $0.7 million on net loss before income taxes of $2.9 million compared to income tax expense of $0.2 million on net income before income taxes of $0.4 million for the three months ended March 31, 2024. The effective tax rates were 24.0% and 35.2% for three months ended March 31, 2025 and 2024, respectively. The decrease in the effective tax rate from the prior year period is due to federal tax credits expected from production on marginal natural gas wells for the calendar year 2024.

Nine Months Ended March 31, 2025 and 2024

We reported a net loss of $1.9 million and net income of $2.8 million for the nine months ended March 31, 2025 and 2024, respectively. The following table summarizes the comparison of financial information for the periods presented:

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

(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.

Revenues

Crude oil, natural gas and NGL revenues were $64.7 million for each of the nine months ended March 31, 2025 and 2024. An increase in production volumes were offset by the decrease in our average realized price per BOE. Average daily equivalent production increased 5.7% from 6,651 BOEPD in the prior year period to 7,033 BOEPD in the current period primarily as a result of the SCOOP/STACK Acquisitions in February 2024 and first production of our wells at Chaveroo Field in early February 2024, which collectively increased production by approximately 1,000 BOEPD over the prior year period. The increase in production was partially offset by natural production declines in our other fields. Our average realized commodity price (excluding the impact of derivative contracts) for the nine months ended March 31, 2025 decreased approximately $1.76 per BOE, or 5.0%, over the prior year period as our realized crude oil decreased 8.0% and realized natural gas prices decreased 4.7% from the nine months ended March 31, 2024.

Lease Operating Costs

Ad valorem and production taxes were $4.3 million and $4.0 million for the nine months ended March 31, 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 $2.25 per BOE and $2.19 per BOE for the nine months ended March 31, 2025 and 2024, respectively.

Gathering, transportation and other costs were $8.6 million for the nine months ended March 31, 2025 compared to $6.9 million for the nine months ended March 31, 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 $1.3 million over the prior year period. On a per unit basis, gathering, transportation and other costs were $4.46 per BOE and $3.79 per BOE for the nine months ended March 31, 2025 and 2024, respectively.

Other lease operating costs were $25.1 million for the nine months ended March 31, 2025 compared to $25.9 million for the nine months ended March 31, 2024. Other lease operating costs decreased primarily due to reduced CO2 purchases at Delhi. CO2 purchases resumed in late October of 2024 and we had net purchases of $2.6 million of CO2 for the nine months ended March 31, 2025 compared to net purchases of $4.2 million in the year-ago period. Partially offsetting the reduction in CO2 purchases were cost increases due to the SCOOP/STACK Acquisitions in February 2024, which increased other lease operating costs by $0.9 million over the prior year period. On a per unit basis, other lease operating costs decreased to $13.00 per BOE for the nine months ended March 31, 2025 from $14.18 per BOE in the nine months ended March 31, 2024.

Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased $1.3 million or 9.3% from $13.7 million to $15.0 million for the nine months ended March 31, 2025 primarily due to an increase in the depletion rate and increase in depletable assets. On a per unit basis, depletion expense was $7.76 per BOE and $7.48 per BOE for the nine months ended March 31, 2025 and 2024, respectively. The depletion rate of our unit of production calculation increased due to an increase in our depletable base as a result of our SCOOP/STACK Acquisitions and capital expenditures since the year-ago period.

General and Administrative Expenses

General and administrative expenses for the nine months ended March 31, 2025 and 2023 were each $5.9 million. On a per unit basis, general and administrative expenses were $3.06 per BOE and $3.25 per BOE for the nine months ended March 31, 2025 and 2024, respectively. The decrease on a per unit basis is primarily the result of the increase in production for the current year period.

Stock-based Compensation Expense

Stock-based compensation expense for the nine months ended March 31, 2025 increased $0.3 million to $1.9 million compared to $1.6 million for the year-ago period. The increase is associated with new awards granted since the year-ago period.

Net Gain (Loss) on Derivative Contracts

We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. Financial hedges are a requirement under our Senior Secured Credit Facility and help establish commodity price floors, contributing to stable cash flows when derivative contracts are settled. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the unaudited condensed consolidated statements of operations. The amounts recorded on the unaudited condensed consolidated statements of operations related to derivative contracts represent the (i) gains (losses) related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) gains (losses) on settlements of derivative contracts for positions that have settled or been realized. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized gains (losses) on our average realized prices for the periods presented. As a result of our 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 forward commodity prices, particularly for natural gas, as of March 31, 2025 as compared to June 30, 2024, resulted in a net unrealized loss for the mark-to-market of our hedges for the nine months ended March 31, 2025. As of March 31, 2025, we had $0.9 million derivative assets, $0.8 million of which was classified as current, and $5.2 million derivative liabilities, 3.5 million of which was classified as current. Subsequent to the end of the quarter through May 2025, we have seen increased volatility in the crude oil and natural gas commodity markets and we expect to see continued volatility in the fair value of our derivative contracts.

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

Interest Expense

Interest expense increased $1.7 million for the nine months ended March 31, 2025 compared to the prior year period primarily due to borrowings drawn on our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions in February 2024. The weighted average interest rate on our borrowings was 7.59% for the nine months ended March 31, 2025 compared to 8.13% for the nine months ended March 31, 2024.

Income Tax (Expense) Benefit

For the nine months ended March 31, 2025, we recognized income tax benefit of $0.6 million on net loss before income taxes of $2.5 million compared to income tax expense of $1.2 million on net income before income taxes of $4.0 million for the nine months ended March 31, 2024. The effective tax rates were 22.9% and 29.2% for nine months ended March 31, 2025 and 2024, respectively. The decrease in the effective tax rate from the prior year period is due to federal tax credits expected from production on marginal natural gas wells for the calendar year 2024.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements. The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires that we select certain accounting policies and make estimates and assumptions that affect the reported amounts of the assets, liabilities, and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported amounts of revenues and expenses during the reporting period. These policies, together with our estimates, have a significant effect on our unaudited condensed consolidated financial statements. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended June 30, 2024.

Derivative Instruments and Hedging Activity

We are exposed to various risks, including energy commodity price risk, such as price differentials between the NYMEX commodity price and the index price at the location where our production is sold. When oil, natural gas, and natural gas liquids prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we monitor commodity prices to identify the potential need for the use of derivative financial instruments to provide partial protection against declines in oil and natural gas prices. We do not enter into derivative contracts for speculative trading purposes. In accordance with our Senior Secured Credit Facility, we may be required to enter into hedges if we meet certain utilization levels of the borrowing base under the credit facility. We intend to remain in compliance with these covenants and will enter into derivative contracts from time to time to meet the requirements. Additionally, depending on market conditions, financial and other considerations we may enter into additional hedges to meet our objectives of increasing value to shareholders.

We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competitive market makers. For the derivative contracts settled during fiscal 2025 and 2024, we did not post collateral. We account for our derivative activities under the provisions of ASC 815, *Derivatives and Hedging, (“*ASC 815”). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 7, “Derivatives” to our unaudited condensed consolidated financial statements for more details.

Interest Rate Risk

We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents. Additionally, any borrowings under the Senior Secured Credit Facility will bear interest, at our option, at either SOFR plus 2.80%, subject to a minimum SOFR of 0.50%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%. SOFR rates are sensitive to the period of contract and market volatility, as well as changes in forward interest rate yields. Under our current practices, we do not use interest rate derivative instruments to manage exposure to interest rate changes.

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s (“SEC”) rules and forms. This information is accumulated and communicated to our management, including our Principal Executive Officer and Principal Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

As required by SEC Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15(d)-15(e)) as of the end of the quarter covered by this report. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. Based on the foregoing, our Principal Executive Officer and Principal Financial Officer concluded that as of March 31, 2025 our disclosure controls and procedures are effective in ensuring that the information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms.

Under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, during the quarter ended March 31, 2025, we have determined that there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.