EVOLUTION PETROLEUM CORP

Previous wording

“Current quarter” refers to the three months ended December 31, 2024, our second quarter of fiscal year 2025.

Current wording

“Current quarter” refers to the three months ended March 31, 2025, our third quarter of fiscal year 2025.

Previous wording

“Year-ago quarter” refers to the three months ended December 31, 2023, our second quarter of fiscal year 2024.

Current wording

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

Previous wording

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 oilfield 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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

Our non-operated interests in the Chaveroo oilfield 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”).

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

Our non-operated interests in the Delhi Field, a CO 2-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.

Current wording

Our non-operated interests in the Delhi Field, a CO 2-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.

Previous wording

During the six months ended December 31, 2024, crude oil, natural gas and NGL production increased 13% 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 had a modest increase of 1% over the same period despite our increase in production volumes due to declines in commodity prices. Our lease operating costs for the six months ended December 31, 2024 have decreased 10%, or $2.13 per BOE, compared to the year-ago period. See below for a further discussion around our results of operations and cash flow activities.

Current wording

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.

Previous wording

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 period ended December 31, 2024, we sold a total of approximately 0.4 million shares of our common stock under the ATM Sales Agreement for net proceeds of approximately $2.0 million, after deducting an initial $0.2 million in fees for due diligence incurred with the offering. 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.

Current wording

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.

Previous wording

The oil and natural gas industry is a global market impacted by many factors, such as government regulations, particularly in the areas of 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

Current wording

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.

Previous wording

As of December 31, 2024, we had $11.7 million in cash and cash equivalents and $39.5 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 six months ended December 31, 2024 were cash provided by operations. Our primary uses of liquidity and capital resources for the three months ended December 31, 2024 were our cash dividend payments to our common stockholders and development capital expenditures. As of December 31, 2024, working capital was $10.5 million, an increase of $4.6 million from working capital of $5.9 million as of June 30, 2024.

Current wording

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.

Previous wording

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 $39.5 million drawn as of December 31, 2024. The Senior Secured Credit Facility is secured by substantially all of our oil and natural gas properties and matures on April 9, 2026.

Current wording

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.

Previous wording

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 six months ended December 31, 2024, the weighted average interest on our borrowings was 7.80%. 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 December 31, 2024, we were in compliance with all covenants under the Senior Secured Credit Facility.

Current wording

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.

Previous wording

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. On February 12, 2024, in conjunction with the Scoop/Stack Acquisitions, we entered into an amendment to the Senior Secured Credit Facility, which required us to enter into hedges for the next 12-month period, and on a rolling 12-month basis thereafter, covering expected crude oil and natural gas production from proved developed reserves, calculated separately, equal to a minimum of 40% of expected crude oil production each month, or

Current wording

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.

Previous wording

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 $10.5 million as of December 31, 2024. 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.

Current wording

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.

Previous wording

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 period ended December 31, 2024, we sold a total of approximately 0.4 million shares of our common stock under the ATM Sales Agreement for net proceeds of approximately $2.0 million, after deducting an initial $0.2 million in fees for due diligence incurred with the offering; however, we are not obligated to sell any shares of common stock in the future.

Current wording

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.

Previous wording

Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 45 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 February 10, 2025, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on March 14, 2025 and payable on March 31, 2025.

Current wording

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.

Previous wording

During the six months ending December 31, 2024, we incurred $2.2 million on development capital expenditures. During the first half of fiscal 2025, capital spending occurred at our fields, including at SCOOP/STACK where our operators are actively drilling and have brought 10 gross 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 year.

Current wording

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.

Previous wording

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 10 gross wells brought online at SCOOP/STACK during the first six months of the fiscal year, discussed above, and bringing an additional eight gross wells online during the remainder of the year. It also includes the drilling and completion of four new gross wells at Chaveroo Field for development block two, which commenced drilling operations in January 2025, and the drilling and completion of one new well at Delhi Field Test Site V.

Current wording

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.

Previous wording

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 December 31, 2024 were $76.32 per barrel of oil, $2.13 per MMBtu of natural gas and $22.60 per barrel of NGLs. As of December 31, 2024, 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 December 31, 2024 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 January 1, 2025 of $72.44 per barrel and $3.40 per MMBtu, and holding it constant for two months 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.

Current wording

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.

Previous wording

Cash used in investing activities for the six months ended December 31, 2024 decreased $1.9 million compared to the six months ended December 31, 2023 primarily due to the participation of our drilling and completion of three gross wells in the Chaveroo Field in the prior year partially offset by the addition of our SCOOP/STACK properties and associated development capital expenditures since the prior year period.

Current wording

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.

Previous wording

Net cash flows used in financing activities for the six months ended December 31, 2024 decreased $2.0 million compared to the six months ended December 31, 2023 primarily due to proceeds received from the sale of our common stock under our ATM Sales Agreement. For the six months ended, December 31, 2024, we paid $8.1 million in cash dividends to our common stockholders and receivednet proceeds from the sale of common stock under the ATM Sales Agreement of approximately $2.0 million, after deducting and initial $0.2 million of fees for due diligence incurred with the offering. For the six months ended December 31, 2023, we paid $8.0 million in cash dividends to our common stockholders.

Current wording

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 receivednet 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.