Evolution Petroleum Corp: Form 10-K for the period ended Jun 30, 2024

Note: See Glossary of Selected Petroleum Industry Terms starting on page iv.

General

Evolution Petroleum Corporation (“Evolution,” and together with its consolidated subsidiaries, the “Company”, “our”, “we, “us” or similar terms) 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. Our long-term goal is to maximize total shareholder return from a diversified portfolio of long-life oil and natural gas properties built through acquisition and through selective development opportunities, production enhancement, and other exploitation efforts on our oil and natural gas properties.

Recent Developments

Dividend Declaration

On September 9, 2024, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable September 30, 2024.

SCOOP/STACK Acquisitions

On February 12, 2024, we closed the acquisitions of certain non-operated oil and natural gas assets in the SCOOP and STACK plays in central Oklahoma (the "SCOOP/STACK Acquisitions") from Red Sky Resources III, LLC, Red Sky Resources IV, LLC, and Coriolis Energy Partners I, LLC. After taking into account customary closing adjustments and an effective date of November 1, 2023, total combined cash consideration for the SCOOP/STACK Acquisitions was approximately $39.2 million, which includes $43.9 million paid at closing less purchase price adjustments totaling approximately $4.7 million related to net cash flows earned on the properties from the effective date to the closing date.

The acquired assets consist of an average net working interest of approximately 2.6% in 253 producing wells in the SCOOP and STACK plays of the Anadarko Basin in Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties, Oklahoma. The acquisitions also include approximately 4,200 net acres with approximately 300 associated potential drilling opportunities.

Senior Secured Credit Facility

On February 12, 2024, we entered into an amendment to the Senior Secured Credit Facility. This amendment required that we 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 25% of expected crude oil and natural gas production each month over that period. We have the option to choose whether to hedge 40% of expected crude oil production or 25% of expected crude oil and natural gas production.

For further discussion of this amendment and our Senior Secured Credit Facility, see “Liquidity and Capital Resources” within Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations.

Appointment of Chief Accounting Officer

On December 18, 2023, we announced that the Board of Directors approved the appointment of Kelly M. Beatty as Chief Accounting Officer, effective January 1, 2024. Ms. Beatty has been serving as Principal Accounting Officer since December 2022 and has served as the Company’s Controller since February 2022.

Share Repurchase Program

In November 2023, 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, 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. These shares were subsequently cancelled. We may enter into additional Rule 10b5-1 plans in the future, the terms of which will be approved by the Board of Directors.

Chaveroo Oilfield Participation Agreement

On September 12, 2023, we entered into a participation agreement (the “Participation Agreement”) with PEDEVCO for the joint development of the Chaveroo oilfield, a conventional oil-bearing San Andres field located in Chaves and Roosevelt Counties, New Mexico (the “Chaveroo Field”).

Pursuant to the Participation Agreement, we have the right, but not the obligation, to elect to participate in drilling locations on approximately 16,000 gross leasehold acres consisting of all leasehold rights from surface to the base of the San Andres formation, where PEDEVCO currently holds leasehold interest. We have agreed to pay PEDEVCO $450 per acre to acquire a 50% working interest share in the leases associated with the locations that we choose to participate in. The Participation Agreement initially includes up to 80 gross drilling locations across twelve development blocks. We have entered into a standard operating agreement with PEDEVCO serving as the operator with respect to the development of the properties. The Participation Agreement includes customary representations and warranties of the parties and other terms and conditions that are standard in such participation agreements.

As of June 30, 2024, we have incurred approximately $0.8 million, in exchange for a 50% working interest share in approximately 1,600 net acres, associated with five development blocks. As of June 30, 2024, we have participated in the drilling and completion of the first development block which consisted of three gross (1.5 net) wells. Refer to Capital Expenditures below for a further discussion of Chaveroo drilling and completion activities since entering into the Participation Agreement.

Business Strategy

Our business strategy is to maximize total shareholder return based on our assessment of the operating environment and marketplace, subject to our obligations to other stakeholders. The key elements of our strategy to accomplish our goal of maximizing shareholder return are:

• Maintaining a strong balance sheet and conservative financial management;
• Growing the asset base through investment in our existing properties, direct acquisitions of new low decline, long-life oil and natural gas properties, selective development opportunities, or accretive acquisitions of similar companies; and
• Returning cash to shareholders by sustaining and growing our dividend payout over time or repurchases of our shares in the open market.

Properties

Our oil and natural gas properties consist of non-operated interests in the following areas: the SCOOP and STACK plays of the Anadarko Basin located in central Oklahoma; the Chaveroo oilfield in Chaves and Roosevelt Counties of New Mexico; the 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; as well as small overriding royalty interests in four onshore central Texas wells.

SCOOP/STACK – Central Oklahoma

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 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.

Average net daily production from the date of acquisition through June 30, 2024 was 1.4 MBOEPD. For the year ended June 30, 2024, our average net daily production from the SCOOP/STACK properties consisted of 47% natural gas, 37% oil, and 16% NGLs. Hydrocarbons produced from our SCOOP/STACK properties are sold to various purchasers throughout the mid-continent.

Chaveroo Field – Chaves and Roosevelt Counties, New Mexico

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

Average net daily production from the date of first production in February 2024 through June 30, 2024 was 0.2 MBOEPD. For the year ended June 30, 2024 our average net daily production from the Chaveroo Field properties consisted of 90% oil, 7% natural gas, and 3% NGLs. Oil produced from our Chaveroo Field properties is sold to various purchasers in New Mexico and gas and NGLs are sold to Targa Resources Corp.

Jonah Field – Sublette County, Wyoming

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 950 net acres all held by production. The properties are operated by Jonah Energy (“Jonah”).

For the year ended June 30, 2024 our average net daily production from the Jonah Field properties was 1.8 MBOEPD consisting of 89% natural gas, 6% NGLs, and 5% oil. Hydrocarbons produced from our Jonah Field properties are sold to West Coast markets.

Williston Basin – Williston, North Dakota

Our non-operated interests in the Williston Basin, oil and natural gas producing properties, consist of approximately 39% average net working interest and approximately 33% average net revenue interest located on approximately 43,000 net acres (approximately 93% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota. The properties are operated by Foundation Energy Management (“Foundation”).

For the year ended June 30, 2024, our average net daily production from the Willison Basin properties was 0.5 MBOEPD consisting of 81% oil, 11% NGLs, and 8% natural gas. The primary producing reservoirs are the Three Forks, Pronghorn, and Bakken formations. Hydrocarbons produced from the Williston Basin properties are sold to local refineries and purchasers.

Barnett Shale – North Texas

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) located on approximately 21,000 net acres held by production across nine North Texas counties (Bosque, Denton, Erath, Hill, Hood, Johnson, Parker, Somervell, and Tarrant), in the Barnett Shale. The oil and natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by six other operators.

For the year ended June 30, 2024, our average net daily production from the Barnett Shale properties was 2.6 MBOEPD consisting of 74% natural gas, 25% NGLs, and 1% oil. The producing reservoir is the Barnett Shale, which is also the source rock. Hydrocarbons produced from our Barnett Shale properties are sold to Gulf Coast markets.

Hamilton Dome – Hot Springs County, Wyoming

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 unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company (“Merit”), a private oil and natural gas 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.

For the year ended June 30, 2024, our average net daily production from the Hamilton Dome Field properties was 0.4 MBOEPD consisting of 100% oil. The primary producing reservoirs in the field are the Tensleep and Phosphoria. Produced oil from the field is subject to Western Canadian Select pricing.

Delhi Field – Enhanced Oil Recovery CO2 Flood – Onshore Louisiana

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 (“Denbury”), which was acquired by Exxon Mobil Corporation (“ExxonMobil”) on November 2, 2023. The unitized Delhi Field, of which we hold approximately 3,200 net acres, is located in northeast Louisiana in Franklin, Madison, and Richland Parishes.

For the year ended June 30, 2024, our average net daily production from the Delhi Field properties was 1.0 MBOEPD consisting of 78% oil and 22% NGLs. The primary producing reservoirs in the field are the Tuscaloosa and Paluxy formations. Produced oil from the field is priced off of Louisiana Light Sweet (“LLS”) crude, which often trades at a premium to West Texas Intermediate (“WTI”).

Refer to “Production volumes, average sales price and average production costs” table below for further information regarding our properties and their fiscal year results.

Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues

The Securities and Exchange Commission (“SEC”) sets rules related to reserve estimation and disclosure requirements for oil and natural gas companies. These rules require disclosure of oil and natural gas proved reserves by significant geographic area, using the trailing 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, rather than year-end prices, and allows the use of new technologies in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Subject to limited exceptions, the rules also require that proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years.

There are numerous uncertainties inherent in estimating quantities of proved reserves and estimates of reserves quantities and values must be viewed as being subject to significant change as more data about the properties becomes available.

Summary of Oil & Gas Reserves for Fiscal Year Ended 2024

Our proved reserves as of June 30, 2024, denominated in thousands of barrels of oil equivalent (“MBOE”), were estimated by our independent reservoir engineers, Netherland, Sewell & Associates, Inc. (“NSAI”), DeGolyer and MacNaughton (“D&M”) and Cawley, Gillespie and Associates, Inc. (“CG&A”), all worldwide petroleum consultants.

NSAI evaluated the reserves for our SCOOP/STACK, Jonah Field and Williston Basin properties. NSAI began evaluating these properties when we acquired each of them. The scope and results of their procedures are summarized in a letter from the firm, which is included as Exhibit 99.1 to this Annual Report on Form 10-K.

D&M evaluated the reserves for our Barnett Shale, Hamilton Dome, and Delhi Field properties. The scope and results of their procedures are summarized in a letter from the firm, which is included as Exhibit 99.2 to this Annual Report on Form 10-K.

CG&A evaluated the reserves for our Chaveroo Field properties. CG&A has a history with the field as it evaluates reserves for the operator of the field. The scope and results of their procedures are summarized in a letter from the firm, which is included as Exhibit 99.3 to this Annual Report on Form 10-K.

The following table sets forth our estimated proved reserves as of June 30, 2024. For additional reserve information, see our Supplemental Disclosure about Oil and Natural Gas Properties (unaudited) to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data. The New York Mercantile Exchange (“NYMEX”) previous 12-month unweighted arithmetic average first-day-of-the-month price used to calculate estimated revenues was $79.45 per barrel of oil and $2.32 per MMBtu of natural gas. The net price per barrel of NGLs was $23.86, which does not have any single comparable reference index price. The NGL price was based on historical prices received. For periods for which no historical price information was available, we used comparable pricing in the geographic area. Pricing differentials were applied based on quality, processing, transportation, location and other pricing aspects for each individual property and product.

Proved Reserves as of June 30, 2024

(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.

Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with Oversight for the Company’s Overall Reserve Estimation Process

Our policies regarding internal controls over reserves estimates require such estimates to be prepared by an independent petroleum engineering firm under the supervision of our internal reserve engineering team, which includes our Chief Operating Officer (“COO”), J. Mark Bunch. Our internal reserve engineering team has a combined experience of over 80 years in Petroleum Engineering. Our COO, the person responsible for overseeing the preparation of our reserves estimates, has a Bachelor of Science Degree in Petroleum Engineering from Texas A&M University, is a registered Professional Engineer in the State of Texas (No. 86704), has over 40 years of oil and natural gas experience including large independents and financial firm services for projects and acquisitions. Our Board of Directors also has oversight of our reserve estimation process and contains a Reserves Committee with William Dozier, an independent director who is a Registered Professional Engineer in the State of Texas (No. 47279) with experience in energy company reserve evaluations. Such reserve estimates comply with generally accepted petroleum engineering and evaluation principles, definitions, and guidelines as established by the SEC.

The reserves information in this filing is based on estimates prepared by NSAI, D&M and CG&A. The person responsible for the preparation of the reserve report at NSAI is Matthew D. Pankey, P.E., Petroleum Engineer. Mr. Pankey, a licensed Professional Engineer in the State of Texas (No. 142931), has been practicing consulting petroleum engineering at NSAI since 2019 and has over six years of prior industry experience. Mr. Pankey received a Bachelor of Science degree in Chemical Engineering in 2012 from Auburn University. The person responsible for the preparation of the reserve report at D&M is Dr. Dilhan Ilk, P.E., Executive Vice President. Dr. Ilk received a Bachelor of Science degree in Petroleum Engineering in 2003 from Istanbul Technical University and a Master’s degree and Doctorate in Petroleum Engineering in 2005 and 2010, respectively, from Texas A&M University, and he has in excess of 14 years of experience in oil and natural gas reservoir studies and evaluations and is a licensed Professional Engineer in the state of Texas (No. 139334). The person responsible for the preparation of the reserve report at CG&A is W. Todd Brooker,

P.E., President. Mr. Brooker received a Bachelor of Science degree in Petroleum Engineering in 1989 from the University of Texas at Austin and is a registered Professional Engineer in the State of Texas (No. 83462). Mr. Brooker joined CG&A in 1992 and has over 30 years of experience in engineering and geological services.

We provide NSAI, D&M and CG&A with our property interests, production, current operating costs, current production prices, estimated abandonment costs and other information in order for them to prepare the reserve estimates. This information is reviewed by our senior management team and designated operations personnel to ensure accuracy and completeness of the data prior to submission to the reserve engineers. The scope and results of NSAI’s, D&M’s and CG&A’s procedures, as well as their professional qualifications, are summarized in the letters included as Exhibit 99.1, Exhibit 99.2 and Exhibit 99.3, respectively, to this Annual Report on Form 10-K.

Proved Undeveloped Reserves

During the year ended June 30, 2024 our proved undeveloped (“PUD”) reserves changed as follows:

(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.

Our PUD reserves were 7.7 MMBOE as of June 30, 2024, with related future development costs of approximately $90.5 million, which are primarily associated with the Williston Basin and Chaveroo Field and to a lesser extent our SCOOP/STACK properties, where we hold a smaller average net working interest, and the Delhi Field. Extensions of 4.5 MMBOE are primarily associated with new wells at SCOOP/STACK, subsequent to our acquisition, and Chaveroo Field. Transfers of 0.1 MMBOE are associated with two Delhi wells placed online during the first fiscal quarter of 2024. The net downward revisions were due primarily to adjustments made to the Williston Basin development plan. These adjustments include updated economic assumptions to drill and complete wells, changes to the specific well locations on the drilling plan based on continuous technical analysis of the acreage, and the development timing of the project that maximizes the efficiency of our capital projects. The positive revisions in natural gas and NGLs are associated with changes in type curves at SCOOP/STACK subsequent to our acquisition. Under SEC reporting requirements, our PUD reserves include only those reserves in which the Company has current plans to develop within five years. See “Drilling and Present Activities” below for a further discussion of our expected development of the PUDs associated with Williston Basin, Chaveroo Field, SCOOP/STACK and Delhi Field.

Drilling and Present Activities

Currently, none of our oil and natural gas properties are operated by us. We therefore rely on information from our operators regarding near-term drilling programs. There are no plans to drill new wells in fiscal year 2025 in the Jonah Field, the Barnett Shale, and the Hamilton Dome Field. At this time, operators of our properties at SCOOP/STACK, Williston Basin, Hamilton Dome Field and Delhi Field are periodically running workover rigs focusing on projects to return wells to production that have experienced mechanical issues.

At SCOOP/STACK, we currently expect 13 gross wells to be brought online during fiscal year 2025. 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, the next development block is currently planned to begin drilling during the second quarter of fiscal 2025, with production estimated to commence during the second half of fiscal 2025. At the Williston Basin, we anticipate that fiscal year 2025 will be used to finalize permits, maximize economic efficiencies in vendor contracts, and prepare for initiating a drilling program to exploit the Three Forks formation on our acreage. We envision production to begin in the second quarter of fiscal year 2026. At Delhi Field, the third-party operator is planning to drill three new wells within Test Site V. The first of these three new wells is expected to come online during the second half of fiscal 2025.

For further discussion, see “Capital Expenditures” within Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations.

Production volumes, average sales price and average production costs

The following table summarizes our crude oil, natural gas, and natural gas liquids production volumes, average sales price per unit and average daily production on an equivalent basis for the periods indicated:

(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) Average daily production presented in the table above represents our fiscal year production divided by 366 days in the year for fiscal year 2024. At SCOOP/STACK and Chaveroo Field, our average daily production since SCOOP/STACK’s acquisition date of February 12, 2024 and first production at Chaveroo Field beginning February 2024 through June 30, 2024, was 1.4 MBOEPD and 0.2 MBOEPD, respectively.

(3) Average daily production presented in the table above represents our fiscal year production divided by 365 days in the year for fiscal years 2023 and 2022. At Williston and Jonah, our average daily production since their respective acquisition dates of January 14, 2022 and April 1, 2022 through June 30, 2022, was 0.5 MBOEPD and 2.1 MBOEPD, respectively.

The following table summarizes our production costs, and production costs per unit for the periods indicated:

Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which we own a working interest as of June 30, 2024.

Acreage

The following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30, 2024. Developed acreage refers to acreage on which wells have been drilled or completed to a point that would allow production of oil and natural gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and natural gas in commercial quantities whether or not the acreage contains proved reserves.

(1) Except for our undeveloped acreage in the SCOOP/STACK, Oklahoma, which will expire in 2026 if we do not establish production in paying quantities on the units in which such acreage is included to maintain the lease and our acreage at the Williston Basin, North Dakota (see expiration table below), all acreage, including any undeveloped, nonproductive or undrilled acreage, is held by existing production as long as continuous production is maintained in the unit.

(2) This table excludes acreage attributable to small overriding royalty interests retained in various formations in the Texas Giddings Field area. Except for de minimis production that began on two leases during late fiscal year 2019, none of such acreage is currently producing and our interests are subject to expiration if leases are not maintained by others or commercial production is not established. It does not currently appear likely that we will obtain any significant value from these interests and no reserves have been assigned to any of the Giddings’ interests.

The table below reflects our net undeveloped acreage in Williston Basin, North Dakota as of June 30, 2024 that will expire each year if we do not establish production in paying quantities on the units in which such acreage is included to maintain the lease:

(1) Excluded 2,747 net acres held by existing production as long as continuous production is maintained in the unit.

Markets and Customers

Our production is marketed to third parties in a manner consistent with industry practices. In the United States market where our properties are operated, crude oil, natural gas, and NGLs are readily transportable and marketable. In the Jonah Field, we take our natural gas and NGL working interest production in-kind and market separately to purchasers on six-month contracts for natural gas and to Enterprise Products Partners L.P. for NGLs. We do not currently market our share of oil, natural gas, or NGLs production from any other field separately from the operators’ shares of production. Although we have the right to take our working interest production in-kind, we are currently selling our production through the field operators pursuant to the delivery and pricing terms of their sales contracts. Under such arrangements, we typically do not know the identity of the buyers.

As a non-operator, we are highly dependent on the success of our third-party operators and the decisions made in connection with their operations. With the exception of the Jonah Field, our third-party operators sell our oil, natural gas, and NGLs to purchasers, collect the cash, and distribute the cash to us. In the year ended June 30, 2024, four individual purchasers, Denbury, Diversified, Foundation, and Merit, each accounted for more than 10% of our total revenues, collectively representing approximately 69% of our total revenues for the year. In the year ended June 30, 2023, three individual purchasers, Diversified, Denbury, and Conoco Phillips, each accounted for more than 10% of our total revenues, collectively representing approximately 65% of our total revenues for the year.

The loss of a purchaser at any of our major producing properties or disruption to pipeline transportation from these fields could adversely affect our net realized pricing and potentially our near-term production levels.

Market Conditions

Prices we receive for crude oil, natural gas, and NGLs are influenced by many factors that are beyond our control, the exact effect of which is difficult to predict. These factors include changes in supply and demand, the relative strength of the U.S. dollar, government regulation, weather, and actions of major foreign producers.

Oil and natural gas prices over the past few years have been volatile and we expect that volatility to continue. Worldwide factors such as global health pandemics, geopolitical, international trade disruptions and tariffs, macroeconomics, supply and demand, refining capacity, petrochemical production, and derivatives trading, among others, influence prices for oil, natural gas, and NGLs. Local and domestic factors also influence prices for oil, natural gas, and NGLs and include increasing or decreasing production trends, quality differences, regulation, legislation and transportation issues unique to certain producing regions and reservoirs.

Competition

The oil and natural gas industry is highly competitive for prospects, acreage, and capital. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staff and greater capital resources. Competitors are national, regional, or local in scope and compete on the basis of financial resources, technical prowess or local knowledge. The principal competitive factors in our industry are expertise in given geographical areas and geologic systems and the ability to efficiently conduct operations, achieve technological advantages, identify and acquire economically producible reserves, and obtain capital at rates that allow economic investments.

Risk Management

We are exposed to certain risks relating to our ongoing business operations, including commodity price risk. In accordance with our company strategy and the covenants under the Senior Secured Credit Facility, derivative instruments are occasionally utilized to hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales of future oil and natural gas production. We do not enter into derivative contracts for speculative trading purposes.

While there are many different types of derivative instruments available, historically we have used costless collars, stand alone put options, and fixed-price swaps to attempt to manage price risk. Costless collar agreements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. All costless collar agreements provide for payments to counterparties if the settlement price under the agreement exceeds the ceiling and payments from the counterparties if the settlement price under the agreement is below the floor. Stand alone put options are floors that are purchased for a cost and provide that counterparties make payments to us if the settlement price is below the established floor. The fixed-price swap agreements call for payments to, or receipts from, counterparties depending on whether the index price of oil or natural gas for the period is greater or less than the fixed price established for the period contracted under the fixed-price swap agreement.

It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. We will continue to evaluate the benefit of employing derivatives in the future. Our hedge strategies and objectives may change as our operational profile changes. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Note 7, “Derivatives” to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data for additional information.

Government Regulation

As an oil and natural gas exploration and production company, our interests are subject to numerous legal requirements.

Regulation of Oil and Natural Gas Production

Federal, state and local authorities have promulgated extensive rules covering oil and natural gas exploration, production and related operations. Those regulations require our third-party operator to obtain permits, post bonds and submit reports. They also may address conservation, including unitization or pooling of oil and natural gas properties, well locations, the method of drilling and casing wells, surface use and restoration of properties where wells are drilled, sourcing and disposal of water used in the process of drilling, completion and abandonment, the establishment of maximum rates of production from wells, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce and to limit the number of wells or the locations at which we can produce. Moreover, many states impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdictions. Failure to comply with any applicable legal requirements may result in substantial penalties. Because such regulations are frequently amended or reinterpreted, we are unable to predict future compliance costs or impacts. Significant expenditures may be required to comply with governmental laws and regulations, however, and may have a material adverse effect on our financial condition and results of operations.

Regulation of Transportation of Oil and Natural Gas

The prices for crude oil, condensate and natural gas liquids and natural gas are negotiated and not currently regulated. But Congress, which has been active in oil and natural gas regulation, could impose price controls in the future.

Our sales of crude oil and natural gas are affected by the availability, terms and cost of transportation. The Federal Energy Regulatory Commission (“FERC”) primarily regulates interstate oil and natural gas transportation rates. In some circumstances, FERC regulations also may affect intrastate pipelines. In addition, states may impose on intrastate pipelines various obligations relating to such matters as safety, environmental protection, nondiscriminatory take and pay rates. The basis for intrastate oil and natural gas pipeline regulation, and the degree of regulatory oversight and scrutiny given to such matters, vary from state to state. To the extent effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil and natural gas transportation rates will not affect our business in any way that is of material difference from those of our competitors who are similarly situated.

Environmental Matters

Our properties are subject to extensive and changing federal, state and local laws and regulations relating to the protection of the environment, worker safety and human health. Such requirements may address:

• the generation, storage, handling, emission, transportation and disposal of materials;
• reclamation or remediation of sites, including former operating areas;
• the acquisition of a permit or other authorization;
• air emissions;
• protection of water supplies;
• limits on construction, drilling and other activities in wilderness or other environmentally sensitive areas; and
• assessment of environmental impacts.

Failure to comply with such requirements may result in a variety of sanctions, including fines, administrative orders and injunctions. In addition, issuing authorities may revoke, adversely condition or deny permits necessary for our operations. In the opinion of management, our properties are in substantial compliance with applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on our company, as well as the oil and natural gas industry in general. Significant environmental requirements that may affect our operations are described below.

The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict liability, and in some cases joint and several liability, on owners and operators of sites and on persons who arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for neighboring landowners or other third parties to also file claims for personal injury and property damage allegedly caused by any hazardous substances released into the environment. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” our operations do entail handling other chemicals that may be subject to the statute. In addition, state laws affecting our properties may impose cleanup liability relating to petroleum and petroleum related products. The Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste.” Violations may result in substantial fines. Although RCRA currently classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous, thereby subjecting our operations to more stringent handling and disposal requirements. In some circumstances, moreover, RCRA authorizes both the federal government and private persons to seek injunctions requiring the cleanup of wastes, whether hazardous or non-hazardous.

The Endangered Species Act (“ESA”) protects fish, wildlife and plants that are listed as threatened or endangered. Under the ESA, exploration and production operations may not significantly impair or jeopardize a protected species or its habitat. The ESA provides for criminal penalties for willful violations. Our operations also may be subject to other statutes that protect animals and plants such as the Migratory Bird Treaty Act. Although we believe that our properties are in compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject our company (directly or indirectly through our third-party operators) to significant expenses to modify operations, could force discontinuation of certain operations altogether and could limit the locations our third-party operators may utilize in the future.

The Clean Air Act (“CAA”) is the comprehensive federal law addressing sources of air emissions. Oil and natural gas production and natural gas processing operations are among the many source categories subject to the CAA. Regulated emissions from oil and natural gas operations include sulfur dioxide, volatile organic compounds (“VOCs”) and hazardous air pollutants such as benzene, among others.

In particular, the Environmental Protection Agency (“EPA”) announced regulations in December 2023 that impose more comprehensive restrictions on emissions of methane (a greenhouse gas) and VOCs from new, existing, and modified facilities in the oil and gas sector (such as wells and storage tank batteries). Among other things, the rule sets new emissions standards for certain equipment; requires routine monitoring for and repair of leaks at well sites, centralized production facilities, and compressor stations; limits flaring from existing oil wells; and prohibits flaring from new oil wells. EPA also established a “Super Emitter Program” to authorize third parties to detect “super emitter events” at operators’ sites and report them to EPA. The regulations do provide phase-in periods for certain requirements. And State plans for existing sources are due 24 months after the rule’s effective date. States can either adopt the rule’s presumptive standards or develop their own requirements that are at least as strict as EPA’s. These regulations or practices and any other new rules requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our business, results of operations and financial condition.

The Clean Water Act (the “CWA”) is the primary federal law controlling the discharge of produced waters and other pollutants into waters of the United States. Permits must be obtained for such discharges and to conduct construction activities in waters and wetlands. Some states also require permits for discharges or operations that may impact groundwater.

The CAA, CWA and comparable state statutes authorize civil, criminal and administrative penalties for violations. Further, the CWA and Oil Pollution Act may impose liability on owners or operators of onshore facilities that impact surface waters.

Pursuant to the Safe Drinking Water Act, EPA (or an authorized state) regulates the construction, operation, permitting, and closure of injection wells used to place oil and natural gas wastes and other fluids underground for enhanced hydrocarbon recovery, storage or disposal. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Underground injection associated with oil and gas operations, particularly the disposal of produced water, has been linked in some cases to localized earthquakes. This in turn has led to new legislative and regulatory initiatives, which have the potential to restrict injection in certain wells or limit operations in certain areas.

Certain of the oil and natural gas production in which we have an interest is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection into the formation of water, sand and chemicals under pressure to stimulate production. From time to time, legislation has been proposed in the United States Congress to repeal the Safe Drinking Water Act’s exemption for hydraulic fracturing from the definition of “underground injection” and to require federal permitting of hydraulic fracturing. If ever enacted, such legislation would add to costs for hydraulic fracturing.

Scrutiny of hydraulic fracturing activities continues in other ways. Several states where our properties are located have proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. A number of municipalities likewise have enacted bans on hydraulic fracturing. We cannot predict whether any other legislation restricting hydraulic fracturing will be enacted and if so, what its provisions would be. If additional levels of regulation and permits were to be required through the adoption of new laws and regulations at the federal, state or local level, it could lead to delays, increased operating costs and process prohibitions that could materially adversely affect our revenue and results of operations.

The National Environmental Policy Act (“NEPA”) requires federal agencies to assess the environmental effects of their proposed actions prior to making decisions. Among the broad range of actions covered by NEPA are decisions on permit applications and federal land management. Many of the activities of our third-party operators involve federal decisions subject to NEPA. Such federal actions may trigger robust NEPA review, which could lead to delays and increased costs that could materially adversely affect our revenues and results of operations. The Biden Administration reversed changes to NEPA rules enacted under the Trump Administration that had been intended to streamline NEPA review. The revised regulations lay the foundation for additional scrutiny of impacts on climate change, which could affect the assessment of projects ranging from oil and gas leasing to development on public and Indian lands.

Climate Change

Climate change has become a major public concern and policy issue in the United States and around the world. Much of the debate has focused on greenhouse gas (“GHG”) emissions from oil and natural gas, particularly carbon dioxide and methane.

In the United States, there is no comprehensive federal regulatory statute addressing climate change, although Congress does periodically consider such measures. At the federal level, the United States therefore has primarily addressed climate change through executive actions and regulatory initiatives pursuant to existing statutes. These include rejoining the Paris Agreement on climate change, the Biden Administration’s commitment to cut greenhouse gas emissions by 2030 to 50-52 percent of 2005 levels, various executive orders, limiting land available for oil and gas leasing, the United States Methane Emissions Reduction Action Plan (intended to reduce overall methane emissions by 30% below 2020 levels by 2030), and Clean Air Act rules (such as regulation announced in December 2023 to reduce methane emissions from the oil and gas sector). The SEC even promulgated new rules in 2024 that would require disclosure of various specific risks related to climate but promptly issued an order staying their applicability pending resolution of legal challenges. In addition, several states have already implemented or are considering programs to reduce GHG emissions. These include cap and trade programs, promotion of alternative forms of energy, transportation standards and restrictions on particular GHGs. New Mexico, for example, is requiring oil and gas operators to capture 98% of their produced natural gas by December 31, 2026, and is limiting most venting and flaring. To the extent that new climate change measures are adopted, our business may be adversely impacted.

In addition, recent court decisions have left open the question of whether tort claims alleging property damage may proceed under state common law against entities responsible for GHG emissions. Thus, there is some litigation risk for such claims.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources, for example, our products would become more desirable in the market with more stringent limitations on GHG emissions. But in 2022, the United States enacted the Inflation Reduction Act that, among other things, creates a series of financial incentives intended to discourage use of oil and natural gas (including imposing a fee on methane emissions) and to promote alternative sources of energy. Pursuant to that Act, EPA announced a proposed rule in December 2023 that would implement the program for collecting the annual “Waste Emissions Charge” on certain excess methane emissions from oil and gas facilities. By statute, the charge would be $900 per metric ton of methane for 2024, $1,200 per metric ton for 2025, and $1,500 per metric ton each year thereafter. To the extent that our products are competing with lower GHG emitting energy sources such as solar and wind, our products may become less desirable in the market with such government intervention. We cannot predict with any certainty at this time how these possibilities may affect our operations.

Various studies on climate change indicate that extreme weather conditions and other risks may occur in the future in the areas where we operate. Although we have not experienced any material impact from such extreme conditions to date, no assurance can be given that they will not have a material adverse effect on our business in the future.

See discussion captioned “Government regulation and liability for oil and natural gas operations and environmental matters may adversely affect our business and results of operations” in Item 1A. Risk Factors.

Insurance

We maintain insurance on our oil and natural gas properties and operations for risks and in amounts customary in the industry. Such insurance includes, but is not limited to, general liability, excess liability, control of well, operators extra expense, casualty, fraud, and directors and officer’s liability coverage. Not all losses are insured, and we retain certain risks of loss through deductibles, limits, and self-retentions. We do not carry business interruption or lost profits coverage.

Human Capital, Sustainability, and ESG

Employees

As of June 30, 2024, we had eleven full-time employees, not including contract personnel and outsourced service providers. Due to our current focus on non-operating properties, our staff is disproportionately weighted towards higher wage professionals. We believe that we have positive relations with our employees. Our team is broadly experienced in oil and natural gas operations, development, acquisitions, and financing. We follow a strategy of outsourcing most of our property accounting, human resources, administrative, and other non-core functions. For our full-time employees, our benefits package, as determined by our Board of Directors, includes medical, dental, and vision insurance, short-term disability, 401(k) contributions based on a portion of the employee’s base salary, short and long-term performance-based and service-based incentive pay (i.e., annual bonuses and stock awards), and paid time off.

Our workforce is provided with annual training and is expected to sign an acknowledgement regarding our policies and disclosures which include, but are not limited to, the Corporate Sustainability Report (“CSR”), employee handbook, human rights, code of ethics, health and safety, emergency procedures, conflicts of interest, insider trading, bribery, kickbacks, discrimination, diversity, equity, and inclusion.

Sustainability and ESG

In fiscal year 2023, we formed a Sustainability Committee which is responsible for overseeing our Environmental Social Governance (“ESG”) initiatives. In fiscal year 2021-2022, under the supervision of our Board of Directors, the Nominating and Corporate Governance committee, and senior management, the foundation of our sustainability efforts and CSR were led by an ESG Task Force. Evolution’s most recent CSR was published in November 2023. This report is accessible on our website at www.evolutionpetroleum.com (http://www.evolutionpetroleum.com).

The ESG Task Force formalized our existing ESG programs, proposed and implemented new ESG initiatives, monitored adherence to our internal and third-party sustainability standards, and provided public disclosures for our stakeholders. Each year, we continue to disclose, enhance, implement, and provide training for a number of new and existing policies and procedures. These include, but are not limited to: implementing a charitable donation program and employee volunteer initiatives, an annual company-wide ESG training program for both the Board of Directors and our workforce, implementation of safety inspections and health and safety coordinators, and incorporating ESG considerations into our compensation structure.

We are committed to high standards of conduct and ethics in order to contribute to the sustainability of our business. Our core values are the base to support our strategy and long-term success. We believe integrity is paramount and we are committed to developing and producing energy resources in environmentally, socially, and ethically respectful and responsible ways. Our people are critical to our success and as such we promote and maintain a safe and inclusive work environment. We strategically plan for the long-term and strive to maintain capital discipline, stakeholder transparency, and continuous focus on returning capital to shareholders.

We work with third-party operators that share our desire to operate and work responsibly, particularly for the natural environments in which they operate.

Denbury Inc., the operator of our Delhi Field property, and now a subsidiary of ExxonMobil, is an industry leader in Carbon Capture, Utilization and Storage with a network of CO2 EOR operations and the United States’ largest operated system of CO2 transmission pipelines. As of year-end 2022, Denbury reportedly injects over three million tons of captured industrial-sourced CO2 annually, and has a goal to reach Net Zero for Scope 1, Scope 2 and Scope 3 CO2 emissions by 2030, primarily through increasing the amount of captured industrial-sourced CO2 used in their operations.

Jonah Energy, the operator of our Jonah Field property, is one of the leading sustainable natural gas producers in the U.S. In 2021, Jonah was the first and only U.S. company to achieve the Gold Standard Rating, announced by the United Nations Environment Programme International Methane Emissions Observatory.

As a non-operator of our current properties, we do not have direct control over environmental initiatives at a property-level. However, we believe it is important to partner with third-party operators that share our core values and are committed to being environmental stewards as they responsibly produce energy resources. We recognize that the expectations, requirements, and responsibilities of operators regarding safeguarding the environment and environmental stewardship continue to evolve. We are, and will continue to be, committed to supporting our third-party operators as they respond to these expectations, requirements, and responsibilities.

In fiscal year 2023, we implemented our first annual voluntary Environmental Operator Questionnaire to collect various environmental metrics on behalf of our third-party operators. In addition, we host regular operations meetings with our third-party operators in which we discuss asset level operations, expenses, any environmental issues and compliance, including ESG and health and safety related topics. The objectives of these endeavors are to obtain environmental data to better disclose the impact of operations, as well as to be better prepared to work with our operating partners in mitigating potential environmental impacts.

We report in our CSR the estimated Scope 1 and Scope 2 GHG emissions for our corporate office located in Houston, Texas. We are not required to and do not report Scope 1 GHG, or direct, emissions to the EPA as we are not the operator of our oil and natural gas properties, nor do we have financial control over our oil and natural gas properties and operations. We prefer to partner with third-party operators that work to reduce their Scope 1 GHG emissions, and we encourage them to accelerate their efforts as appropriate in this regard. Scope 2 GHG emissions are based on indirect emissions representing purchased electricity. We are one of many tenants leasing space in our corporate office building and do not know the actual amount of electricity used in our space. As such, we estimate our consumption by multiplying the electricity purchased for the entire building by the percentage of the floor area that we occupy. Water use is also reported in the CSR and is calculated in a similar fashion.

We maintain a hotline which operates 24/7/365 and allows anonymous and confidential reporting for employees, consultants, partners, and contractors, including the ability to report concerns or violations of our policies through the phone or internet (Phone: 877-628-7489 / Website: www.epm.alertline.com (http://www.epm.alertline.com)).

Additional Information

We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other reports with the SEC. Our reports filed with the SEC are available free of charge to the general public through our website at www.evolutionpetroleum.com (http://www.evolutionpetroleum.com). These reports are accessible on our website as soon as reasonably practicable after being filed with, or furnished to, the SEC. This Annual Report on Form 10-K and our other filings can also be obtained by contacting: Corporate Secretary, 1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079, or calling (713) 935-0122. These reports are also available at the SEC Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website at www.sec.gov (http://www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition, or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider to be immaterial also may adversely affect us.

Risks Related to Our Business:

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition, results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The price we receive for our oil and natural gas significantly influences our revenue, profitability, access to capital, capital spending, and future rate of growth. At June 30, 2024, approximately 37% of our proved reserves were oil reserves, 41% were natural gas and 22% were NGLs. Oil, natural gas and NGLs are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas, and NGLs have been volatile and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control, including, but not limited to the following:

• changes in global supply and demand for oil and natural gas;
• worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;
• social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States, such as the conflict between Ukraine and Russia and the conflict between Israel and Gaza, and acts of terrorism or sabotage;
• the ability and willingness of the members of OPEC+ to agree and maintain oil price and production controls;
• the price and quantity of imports of foreign oil and natural gas;
• energy transition away from hydrocarbons in response to governmental, scientific, and public concern over the threat of climate change arising from greenhouse gas emissions;
• the relative strength or weakness of the U.S. dollar compared to other currencies;
• the level of global oil and natural gas exploration and production;
• the level of global oil and natural gas inventories;
• localized supply and demand fundamentals of regional, domestic, and international transportation availability;
• weather conditions, natural disasters, and seasonal trends;
• domestic and foreign governmental regulations, including embargoes, sanctions, tariffs, and environmental regulations;
• speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;
• price and availability of competitors’ supplies of oil and natural gas;
• technological advances affecting energy consumption; and
• the price, availability and use of alternative fuels.

Substantially all of our production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices. A decline in oil, natural gas, and NGL prices will reduce our cash flows, borrowing ability, the present value of our reserves, and our ability to develop future reserves. We may be unable to obtain the needed capital or financing on satisfactory terms. Low oil, natural gas, and NGL prices may also reduce the amount of oil, natural gas, and NGL that we can produce economically, which could lead to a decline in our oil, natural gas and NGL reserves. Generally, we hedge substantially less than all of our anticipated oil and natural gas production and typically only with the requirements of our Senior Secured Credit Facility. To the extent that we have not hedged production, any significant and extended decline in oil, natural gas, and NGL prices may adversely affect our financial position.

Our existing developed oil and natural gas production will decline; we may be unable to acquire or develop the additional oil and natural gas reserves that are required in order to sustain our production and business operations.

The volume of production from developed oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Environmental issues, operating problems, or lack of extended future investment in any of our properties would cause our net production of oil, natural gas, and NGLs to decline significantly over time, which could have a material adverse effect on our financial condition.

The types of resources we focus on have substantial operational risks.

Our business plan focuses on the acquisition and development of known resources in partially depleted, naturally fractured, or low permeability reservoirs. Our Chaveroo oilfield, Hamilton Dome Field and Delhi Field properties produce from relatively shallow reservoirs, while our SCOOP/STACK, Jonah Field, Williston Basin and Barnett Shale properties produce from deeper reservoirs. Shallower reservoirs usually have lower pressure, which generally translates into lower reserves volumes in place. Deeper reservoirs have higher pressures and usually more reserves volumes in place, but capturing those reserves often comes at increased drilling and completion costs and risks and, generally, a higher rate of initial production decline. Low permeability reservoirs require substantial stimulation for development of commercial production. Naturally fractured reservoirs require penetration of sufficient un-depleted fractures to establish commercial production. Depleted reservoirs require successful application of newer, or more expensive, technologies to produce incremental reserves. Our approach on the development and application of technologies on these different types of reservoirs could have a material adverse effect on our results of operations.

The CO2-EOR project in the Delhi Field, operated by Denbury, requires significant amounts of CO2 reserves, development capital, and technical expertise, the sources of which to date have been committed by the operator. On November 2, 2023, ExxonMobil acquired Denbury. Additional capital remains to be invested to fully develop the EOR project and maximize the value of the properties. The operator’s failure to manage these and other technical, environmental, operational, strategic, financial, and logistical risks may ultimately cause enhanced recoveries from the planned CO2-EOR project to fall short of our expectations in volume and/or timing. Such occurrences could have a material adverse effect on our results of operations and financial condition.

We have limited control over the activities on properties we do not operate.

All of our property interests are operated by third-party working interest owners, not by us. As a result, we have limited ability to influence or control the operations or future development of such properties, including compliance with environmental, safety, and other standards, or the amount of capital or other expenditures that we will be required to fund with respect to such properties. Operators of these properties may act in ways that are not in our best interest. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs, result in lower production, and materially and adversely affect our financial condition and results of operations.

We will be subject to risks in connection with acquisitions.

We periodically evaluate acquisitions of reserves, properties, prospects, leaseholds, and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including, but not limited to:

• recoverable reserves;
• future oil and natural gas prices and their appropriate differentials;
• development and operating costs;
• potential for future drilling and production;
• validity of the seller’s title to properties, which may be less than expected at closing; and
• potential environmental issues, litigation, and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable at the ground surface or otherwise when an inspection is performed. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Moreover, in the event of such an acquisition, there is a risk that we could ultimately be liable for unknown obligations related to acquisitions and, importantly, that our assumptions regarding future oil and natural gas prices, differentials, reserves, or production could prove materially inaccurate and have a material adverse effect on our financial condition, results of operations, or cash flows.

Our inability to complete acquisitions at our historical rate and at appropriate prices, that support our long-term strategy, could negatively impact our growth rate and stock price.

One of our key strategies is growth through acquisition of low decline, long-life oil and natural gas properties. Our ability to grow revenues, earnings and cash flow at or above our historic rates depends in part upon our ability to identify and successfully acquire and integrate oil and natural gas properties at appropriate prices, and to make appropriate investments that support our long-term strategy. We may not be able to consummate acquisitions at rates similar to the past, which could adversely impact our growth rate and our stock price. Acquisitions are difficult to identify and complete for a number of reasons, including high valuations, competition among prospective buyers or investors, the availability of affordable funding in the capital markets and the need to satisfy applicable closing conditions.

We may encounter difficulties integrating the operations of newly acquired oil and natural gas properties or businesses.

Increasing our reserve base through acquisitions has been an important part of our business strategy. We may encounter difficulties integrating newly acquired oil and natural gas properties or businesses. In particular, we may face significant challenges in consolidating functions and integrating procedures, personnel, and business operations in an effective manner. The failure to successfully integrate such properties or businesses into our Company may adversely affect our business and results of operations. Any acquisition we make may involve numerous risks, including:

• a significant increase in our indebtedness and working capital requirements;
• the inability to timely and effectively integrate the operations of recently acquired businesses or assets;
• the incurrence of substantial costs to address unforeseen environmental and other liabilities arising out of the acquired businesses or assets;
• liabilities arising from the operation of the acquired businesses or assets before our acquisition;
• our lack of drilling or operational history in the areas in which the acquired business operates;
• customer or key employee loss from the acquired business;
• increased administration of new personnel;
• additional costs due to increased scope and complexity of our business;
• potential disruption of our ongoing business; and
• assumptions made on estimated development by the operator may not be accurate or may change.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties. To the extent that we acquire properties substantially different from the properties we currently own or that require different technical expertise, we may not be able to realize the economic benefits of these acquisitions as effectively as with acquisitions within our current footprint and expertise. We may not be successful in addressing these risks or any other problems encountered in connection with any acquisition we may make.

Oil and natural gas development, re-completion of wells from one reservoir to another reservoir, restoring wells to production, and drilling and completing new wells are speculative activities which involve numerous risks and substantial uncertain costs.

Our growth will be partially dependent upon the success of future development programs on our properties. Drilling for oil and natural gas and extracting NGLs and re-working existing wells involve numerous risks. The cost of drilling, completing, and operating wells is substantial and uncertain; drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors beyond our control, including, but not limited to:

• unexpected drilling conditions;
• pressure fluctuations or irregularities in reservoir formations;
• equipment failures or accidents;
• well blowouts and other releases of hazardous materials;
• inability to obtain or maintain leases on economic terms, where applicable;
• the cost and availability of goods and services, such as drilling rigs, fracture stimulation services, and tubulars;
• adverse weather conditions;
• compliance with governmental requirements; and
• shortages or delays in the availability of drilling rigs or crews and the delivery of equipment.

Drilling or re-working is a highly speculative activity. Even when fully and correctly utilized, modern well completion and production techniques, such as Horizontal Drilling or CO2 injection, do not guarantee that we will find and produce oil and/or natural gas in economic quantities. Our future drilling, completion and production activities may not be successful and, if unsuccessful, such failure would have an adverse effect on our future results of operations and financial condition.

We may also identify and develop prospects through a number of methods, some of which may include Horizontal Drilling or tertiary injectants, and some of which may be unproven. The drilling and results for these prospects may be particularly uncertain. We cannot ensure that these projects can be successfully developed or that wells will, if drilled, encounter reservoirs of commercially productive oil or natural gas.

Our oil and natural gas reserves are only estimates and may prove to be inaccurate.

There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values. Our reserves are only estimates that may prove to be inaccurate because of these inherent uncertainties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot always be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves depend upon a number of variable factors. These factors include historical production from the area compared with production from other comparable producing areas, assumptions concerning effects of regulations by governmental agencies, future oil and natural gas product prices, future operating costs, severance and excise taxes, development costs, workover costs, and remedial costs. Some or all of these assumptions utilized in estimating reserve volumes may vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of reserves, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected from reserves may vary substantially depending on the timing and different engineers preparing reserves estimates.

Accordingly, reserve estimates may be subject to downward or upward adjustments. Actual production, revenue, and expenditures with respect to our reserves will likely vary from estimates; such variances may be material. The information regarding discounted future net cash flows included in this report should not be considered as the current market value of the estimated oil and natural gas reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are based on the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor. Interest rates in effect vary from time to time based on risks associated with us or the oil and natural gas industry in general. The Standardized Measure does not necessarily correspond to market value.

Regulatory and accounting requirements may require substantial reductions in reporting proven reserves.

On a periodic basis, we review the carrying value of our oil and natural gas properties under the applicable rules of various regulatory agencies, including the SEC. Under the full cost method of accounting that we use, the after-tax carrying value of our oil and natural gas properties may not exceed the present value of estimated future net after-tax cash flows from proved reserves, discounted at 10%. Application of this “ceiling” test requires pricing future revenues at the previous 12-month average beginning-of-month price and requires a write-down of the carrying value for accounting purposes if the ceiling is exceeded. We may in the future be required to write down the carrying value of our oil and natural gas properties when oil and natural gas prices are depressed or unusually volatile. Whether we will be required to take such a charge will depend in part on the prices of oil and natural gas during the previous period and the effect of reserve additions or revisions and capital expenditures during such period. If a write-down is required, it would result in a current charge to our earnings but would not impact our current cash flow from operating activities. A large write-down could adversely affect our compliance with the current financial covenants under our credit facility, could limit our access to future borrowings under that facility, or require repayment of any amounts that might be outstanding at the time.

Our derivative activities could result in financial losses or could reduce our income.

Under the terms of our Senior Secured Credit Facility, we are required to hedge a certain portion of our anticipated oil and natural gas production for future periods when we reach a defined utilization percentage. We may also elect to hedge additional production volumes from time to time based upon our view of the attractiveness of commodity futures and the risks that downward price fluctuations might pose to our business plans. When we engage in hedging transactions, we may utilize costless collars, fixed price swaps or purchased floors to cost-effectively provide us with some protection against price changes. We have not historically designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our future derivative instruments. Derivative arrangements may also expose us to the risk of financial loss in some circumstances, including, but not limited to, if:

• actual production is less than the volume covered by the derivative instruments;
• the counterparty to the derivative instrument defaults on its contract obligations; or
• there is a change in the expected differential between the underlying price in the derivative instrument and actual price received.

In addition, in a rising commodity price environment, derivative arrangements may limit the extent to which we might benefit from increases in prices of oil and natural gas and may expose us to cash margin requirements.

Our operations, funding required to develop and produce reserves and our growth plans require significant amounts of capital and our ability to access additional capital at acceptable costs is important if we are to fund our operations, grow our reserves and production and execute our growth plans.

Cash flow from our production varies based on commodity prices and may decline along with nature declines in our production. As a consequence, our cash flow may not be sufficient to fund our ongoing or planned activities at all times. From time to time, we may require additional financing in order to fund our operations, acquisitions, exploitation, and development activities. We have, for instance, accessed our credit facility on a routine basis, including, recently, to fund acquisitions. As a result of our SCOOP/STACK Acquisitions, our credit facility has current availability of $10.5 million, and the maximum amount that may be outstanding under our credit facility at any one time is $50.0 million. Further, the size of our credit facility is influenced by many factors, including our production, reserves and prevailing views on future commodity prices, and it may decrease based on developments negatively impacting those and other factors. While ordinarily positive developments in such factors might increase the amount that lenders are willing to lend to us, we are currently at the limit of our lender to increase the size of our credit facility due to limitations that the lender has on the loans it may extend to a single borrower. While we may pursue a syndication or refinance of our credit facility to alleviate this issue, we may be unable to do so upon the terms that are favorable to us. Additionally, access to debt and equity capital markets or other alternatives may also prove unavailable or unattractive at such times or in such amounts as we may require. If we are unable to access adequate capital at acceptable costs, it could adversely affect our ability to expend the necessary capital to replace our reserves, maintain our production and execute our business plans.

Government regulation and liability for oil and natural gas operations and environmental matters may adversely affect our business and results of operations.

Oil and natural gas operations are subject to extensive federal, state, and local government regulations, which may change from time to time. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas from wells below actual production capacity in order to conserve supplies of oil and natural gas. There are federal, state, and local laws and regulations addressing protection of human health and the environment that apply to the development, production, handling, storage, and transportation of oil, natural gas, and their by-products; the disposal of related wastes; the emission of CO2, methane, and other greenhouse gases; the emission of volatile organic compounds; and the management of other substances and materials released, produced or used in connection with oil and natural gas operations. These laws and regulations may affect the costs, manner, and feasibility of our operations by, among other things, requiring us to make significant expenditures in order to comply and restricting the areas available for oil and gas production. Failure to comply with these laws and regulations may result in substantial liabilities to third-parties or governmental entities. In addition, we may be liable for significant environmental damages and cleanup costs, without regard to fault, for releases of hazardous materials on or from property we own or operate, even if we did not cause or contribute to the release. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. The implementation of new, or the modification of existing, laws or regulations, could have a material adverse effect on us, such as by imposing new emission controls, penalties, fines and/or fees, taxes and tariffs on carbon that could have the effect of raising prices to the end user and thereby reducing the demand for our products.

The risks arising out of the threat of climate change, including transition risks and physical risks, may adversely affect our business and results of operations.

The threat of climate change poses both transition risks and physical risks that could have a material adverse effect on us. Transition risks may arise from political and regulatory, legal, technological or financial changes as society tries to safeguard the climate, while physical risks may result from extreme weather events or other shifts in the natural world.

We have been facing increased political and regulatory risks as federal, state and local governments have adopted new measures to restrict sources of greenhouse gas emissions and promote energy alternatives, including the final EPA rule announced in December 2023 to reduce the emission of methane from oil and gas facilities. Many such measures have been proposed, and still more can be expected. From time to time, there are proposals to ban hydraulic fracturing of oil and natural gas wells and to remove more lands, both onshore and offshore, from new hydrocarbon production. Many other actions could be pursued such as more rigorous requirements for drilling and construction permits, stricter greenhouse gas emissions standards for both new and existing sources, further limits on construction of new pipelines, reinstatement of the ban on oil exports, enhanced reporting obligations, taxing carbon emissions and creating further incentives for use of alternative energy sources. These actions may cause operational delays or restrictions, increased operating costs and additional regulatory burdens.

Litigation risks are also increasing for oil and natural gas companies. A number of suits alleging, among other things, that oil and natural gas companies created public nuisances by producing fuels that contributed to climate change have been brought in state or federal court.

Technological changes may drive market demand for products other than oil and natural gas. Wider adoption of hybrid engines and electric cars, for example, would reduce demand for our products. At the same time, our capital and operating costs may increase if we need to add new emission reduction technologies.

There are also financial risks for the petroleum industry. It may become more difficult for us to access the capital markets if the threat of climate change discourages new investment. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices, and some of them may elect not to provide funding for fossil fuel energy companies. Limitation of investments in and financings for the energy industry could result in the restriction, delay or cancellation of drilling programs or development or production activities.

The threat of climate change also may subject our operations and business to severe weather or other natural hazards, such as flooding, drought, wildfires, and extreme temperatures. Any such event could halt production or exploration activities, damage equipment, disrupt transportation, reduce consumer demand and significantly increase our costs.

Poor general economic, business, or industry conditions may have a material adverse effect on our results of operations, liquidity, and financial condition.

During the last few years, concerns over inflation, energy costs, volatile oil and natural gas prices, geopolitical issues, the availability and cost of credit, the United States mortgage market, uncertainties with regard to European sovereign debt, the slowdown in economic growth in large emerging and developing markets, such as China, regional or worldwide increases in tariffs or other trade restrictions, and other issues have contributed to increased economic uncertainty and diminished expectations for the global economy. Concerns about global economic conditions have had a significant adverse impact on domestic and international financial markets and commodity prices. If uncertain or poor economic, business, or industry conditions in the United States or abroad remain prolonged, demand for petroleum products could diminish or stagnate, and production costs could increase. These situations could impact the price at which we can sell our oil, natural gas, and NGLs, affect our vendors’, suppliers’, and customers’ ability to continue operations, and ultimately adversely impact our results of operations, liquidity, and financial condition.

Events outside of our control, including a pandemic or broad outbreak of an infectious disease, such as the global outbreak of a novel strain of the coronavirus (“COVID-19”), may materially adversely affect our business.

We face risks related to pandemics, outbreaks, or other public health events that are outside of our control and could significantly disrupt our operations and adversely affect our financial condition. In December 2019, COVID-19 was identified in Wuhan, China and rapidly spread around the world. This virus and its variants, and governmental actions to contain it, had material adverse economic impacts globally. These and other actions could, among other things, impact the ability of our employees and contractors to perform their duties, cause increased technology and security risk due to extended and company-wide telecommuting, and lead to disruptions in our permitting activities and critical business relationships. Additionally, governmental restrictions intended to contain COVID-19 or future pandemics have in the past, and may in the future, significantly impact economic activity and markets and dramatically reduce actual or anticipated demand for oil and natural gas, adversely impacting the prices we receive for our production. The severity and duration of any such events are uncertain and difficult to predict, as is the extent that such events may have on our business.

Our business could be negatively affected by security threats. A cyber-attack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation, and/or financial loss.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing, and financial activities. We depend on digital technology to estimate quantities of oil and natural gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party operators. Our technologies, systems, networks, seismic data, reserves information, or other proprietary information, and those of our operators, vendors, suppliers, customers, and other business partners may become the target of cyber-attacks or information security breaches. Cyber-attacks or information security breaches could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations or other operational disruptions in our exploration or production operations. Cyber-attacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation, or potential liability. Also, computers control nearly all of the oil and natural gas distribution systems in the United States and abroad. Computers are necessary to transport our oil and natural gas production to market. A cyber-attack directed at oil and natural gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the United States government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against cybersecurity risks may not be sufficient. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

Our insurance may not protect us against all of the operating risks to which our business is exposed.

The oil and natural gas business involves numerous operating hazards such as well blowouts, mechanical failures, explosions, uncontrollable flows of oil, natural gas, or well fluids, fires, formations with abnormal pressures, hurricanes and storms, flooding, pollution, releases of toxic gas, and other environmental hazards and risks, which can result in (1) damage to or destruction of wells and/or production facilities, (2) damage to or destruction of formations, (3) injury to persons, (4) loss of life, or (5) damage to property, the environment or natural resources. While we carry general liability, control of well, and operator’s extra expense coverage typical in our industry, we are not fully insured against all risks incidental to our business. Should we experience any losses, the costs of our premiums may rise, which could in turn reduce the amount of insurance we are able to carry.

The loss of key personnel could adversely affect us.

We depend to a large extent on the services of certain key management personnel, including our executive officers. The loss of one or more key personnel could have a material adverse effect on our operations. In particular, our future success is dependent upon the abilities of our executive officers to source, evaluate, and close deals, raise capital, and oversee our development activities and operations. Presently, we are not a beneficiary of any key man life insurance.

Oilfield service and materials prices may increase, and the availability of such services and materials may be inadequate to meet our needs.

Our business plan to develop or redevelop oil and natural gas resources requires third-party oilfield service vendors and various material providers, which we do not control. We also rely on third-party carriers for the transportation and distribution of our oil and natural gas production. As our production increases, so does our need for such services and materials. Generally, we do not have long-term agreements with our service and materials providers. Accordingly, there is a risk that any of our service providers could discontinue providing services for any reason or we may not be able to source the services or materials we need. Any delay in locating, establishing relationships, and training our sources could result in production shortages and maintenance problems, resulting in loss of revenue to us. In addition, if costs for such services and materials increase, it may render certain or all of our projects uneconomic, as compared to the earlier prices we may have assumed when deciding to redevelop newly purchased or existing properties. Further adverse economic outcomes may result from the long lead times often necessary to execute and complete our redevelopment plans.

We may assume risks and financial responsibility for drilling and completing wells at our Chaveroo oilfield and Williston Basin properties if our third-party operator declines to drill wells and it or other joint interest owners elect not to participate.

As discussed elsewhere in this report, pursuant to agreements related to our interests in the Chaveroo oilfield and Williston Basin properties, we have the ability to propose to the operator a drilling plan for certain wells, which the operator may accept or reject. In the event the operator rejects our proposed drilling plan, we have the right to undertake all necessary activities to drill and complete the wells and related facilities in accordance with our proposed drilling plan. In the event we undertake to do so, and the operator and other joint interest owners elect not to participate, we will bear the entire liability and expense associated with drilling and completing the wells and related facilities, subject only to our right to recoup costs incurred on behalf of non-participating joint interest owners to the extent a well generates sufficient revenues to do so. We thus may be required to bear a share of such expenses to an extent that is disproportionate to our economic interest in the property. If we elect to proceed to drill and complete wells we have proposed and the operator has rejected, we also will bear many of the other risks highlighted elsewhere herein, including, without limitation, failing to find economic quantities of oil and natural gas, drilling accidents, potential environmental liabilities, unavailability of insurance at a reasonable cost to cover associated liabilities, and price increases and delivery delays for required drilling and completion equipment, products and services. Ongoing operations of any wells we elect to drill will be turned over to the operator of the property upon completion.

We cannot market the oil and natural gas that we produce without the assistance of third-parties.

The marketability of the oil and natural gas that we produce depends upon the proximity of our reserves and production to, and the capacity of, facilities and third-party services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities necessary to make the products marketable for end use. The unavailability or lack of capacity of such services and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. A shut-in, delay, or discontinuance could adversely affect our financial condition.

We face strong competition from larger oil and natural gas companies.

Our competitors include major integrated oil and natural gas companies, numerous larger independent oil and natural gas companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources. We may not be able to successfully conduct our operations, evaluate and select suitable properties, or consummate transactions in this highly competitive environment. Specifically, these larger competitors may be able to pay more for development projects and productive oil and natural gas properties and may be able to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may be able to expend greater resources on hiring contract service providers, obtaining oilfield equipment, and acquiring the existing and changing technologies that we believe are, and will be, increasingly important to attaining success in our industry.

We have been, and in the future may become, involved in legal proceedings related to our properties or operations and, as a result, may incur substantial costs in connection with those proceedings.

From time to time we may be a defendant or plaintiff in various lawsuits. The nature of our operations exposes us to further possible litigation claims in the future. There is risk that any matter in litigation could be decided unfavorably against us regardless of our belief, opinion, and position, which could have a material adverse effect on our financial condition, results of operations, and cash flow. Litigation can be very costly, and the costs associated with defending litigation could also have a material adverse effect on our financial condition. Adverse litigation decisions or rulings may damage our business reputation.

Ownership of our oil, natural gas, and mineral production depends on good title to our property.

Good and clear title to our oil, natural gas, and mineral properties is important to our business. Although title reviews will generally be conducted prior to the purchase of most oil, natural gas, and mineral producing properties or the commencement of drilling wells, such reviews do not assure that an unforeseen defect in the chain of title will not arise to defeat our claim. This could result in a reduction or elimination of the revenue received by us from such properties.

Unanticipated changes in effective tax rates or laws or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations.

We are subject to tax by U.S. federal, state, and local tax authorities. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including:

• changes in the valuation of our deferred tax assets and liabilities;
• expected timing and amount of the release of any tax valuation allowances;
• tax effects of stock-based compensation;
• costs related to intercompany restructurings; or
• changes in tax laws, regulations, or interpretations thereof.

For example, in previous years, legislation has been proposed to eliminate or defer certain key U.S. federal income tax deductions historically available to oil and natural gas exploration and production companies. Such proposed changes have included: (1) a repeal of the percentage depletion allowance for oil and natural gas properties; (2) the elimination of deductions for intangible drilling and exploration and development costs; (3) the elimination of the deduction for certain production activities; and (4) an extension of the amortization period for certain geological and geophysical expenditures. Under the current Administration there is an increased risk of the enactment of legislation that alters, eliminates, or defers these or other tax deductions utilized within the industry, which could adversely affect our business, financial condition, results of operations, and cash flows.

In addition, we may be subject to audits of our income, sales, and other transaction taxes by U.S. federal, state, and local taxing authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations.

Risks Associated with our Common Stock

Our stock price has been and may continue to be volatile.

Our common stock has a relatively low trading volume and the market price has been, and is likely to continue to be, volatile. The variance in our stock price makes it difficult to forecast the stock price at which an investor may be able to buy or sell shares of our common stock. The market price for our common stock could be subject to fluctuations as a result of factors that are out of our control, such as:

• actual or anticipated variations in our results of operations;
• changes or fluctuations in the commodity prices of oil and natural gas;
• general conditions and trends in the oil and natural gas industry;
• redemption demands on institutional funds that hold our stock; and
• general economic, political, and market conditions.

Significant ownership of our common stock is concentrated in a small number of shareholders who may be able to affect the outcome of the election of our directors and all other matters submitted to our stockholders for approval.

As of June 30, 2024, our executive officers and directors, in the aggregate, beneficially owned approximately 3.2 million shares, or approximately 9.5% of our outstanding common stock and, based on recent filings with the SEC, we believe one large unaffiliated fund complex owned in excess of 7% of the outstanding shares of our common stock. As a result, a significant percentage of our common stock is concentrated in the hands of relatively few shareholders. These shareholders could potentially exercise significant influence over matters submitted to our stockholders for approval (including the election and removal of directors and any merger, consolidation or sale of all or substantially all of our assets). This concentration of ownership may have the effect of delaying, deferring, or preventing any matter that requires shareholder approval, including a change in control of our company, impede a merger, consolidation, takeover, or other business combination involving our company or discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of our company, which in turn could have an adverse effect on the market price of our common stock.

The market for our common stock is limited and may not provide adequate liquidity.

Our common stock trades on the NYSE American. Trading volume in our common stock is relatively low compared to larger companies. Our holders may find it more difficult to sell their shares, should they desire to do so, based on the trading volume and price of our stock at that time relative to the quantity of shares to be sold.

If securities or industry analysts do not publish research reports about our business, or if they downgrade our stock, the price of our common stock could decline.

Small, relatively unknown companies can achieve visibility in the trading market through research and reports that industry or securities analysts publish. To our knowledge, only two research analysts actively cover our company. The limited number of published reports by securities analysts could limit the interest in our common stock and negatively affect our stock price. We do not have any control over the research and reports these analysts publish or whether they will be published at all. If any analyst who does cover us downgrades our stock, our stock price could decline. If any analyst ceases coverage of our company or fails to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause our stock price to decline.

Our stated objective of returning cash to shareholders is subject to our ability to generate sufficient cash flows to pay dividends on our common stock and to repurchase shares of our common stock, as applicable, and we have, in the past, and may in the future, reduced or eliminate dividend payments and stock repurchases.

Our Board of Directors declared cash dividends on our common stock for the first time in December 2013 and we have declared and paid quarterly cash dividends since that time. Additionally, our Board of Directors has approved stock repurchase programs pursuant to which we have expended $8.6 million to repurchase shares over such period. Although one of our primary objectives is to return cash to shareholders, we are not required to repurchase shares of common stock or to pay dividends thereon and may be contractually or legally prohibited from doing so at certain times. Further, even if we are legally and contractually permitted to do so and have available cash to do so, we may elect to reduce or suspend the payment of dividends or the repurchase of shares of common stock to preserve cash based on the current and future capital requirements of our business, our financial condition, the amount of funds legally available therefor, any contractual restrictions to which we are subject at such time, our expectations about future cash inflows and such other factors as our Board of Directors may consider relevant. Accordingly, there is no certainty that dividends will be declared by our Board of Directors or shares of common stock will be repurchased by us in the future.

There may be future sales or issuances of our common stock, which will dilute the ownership interests of stockholders and may adversely affect the market price of our common stock.

We may in the future issue additional shares of common stock, including securities that are convertible into or exchangeable for, or that represent the right to receive, common stock or substantially similar securities, which may result in dilution to our stockholders. In addition, our stockholders may be further diluted by future issuances under our equity incentive plans. The market price of our common stock could decline as a result of future sales or issuances of a large number of shares of our common stock or similar securities in the market or the perception that such sales or issuances could occur.

Non-U.S. holders may be subject to U.S. income tax and withholding tax with respect to gain on disposition of the Company’s common stock.

We believe we are a U.S. real property holding corporation. As a result, Non-U.S. holders that own (or are treated as owning under constructive ownership rules) more than a specified amount of our common stock during a specified time period may be subject to U.S. federal income tax and withholding on a sale, exchange or other disposition of such common stock, and may be required to file a U.S. federal income tax return.

Investor sentiment towards climate change, fossil fuels, sustainability, and other ESG matters could adversely affect our business and our stock price.

There have been efforts in recent years aimed at the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities, and other groups, to promote the divestment of shares of fossil fuel companies, as well as to pressure lenders and other financial services companies to limit or curtail activities with fossil fuel companies. As a result, some financial intermediaries, investors, and other capital markets participants have reduced or ceased lending to, or investing in, companies that operate in industries with higher perceived environmental exposure, such as the oil and natural gas industry. For example, in December 2020, the State of New York announced that it will be divesting the state’s Common Retirement Fund from fossil fuels. If this or similar divestment efforts are continued, the price of our common stock or debt securities, and our ability to access capital markets or to otherwise obtain new investment or financing, may be negatively impacted.

Members of the investment community are also increasing their focus on ESG practices and disclosures, including practices and disclosures related to greenhouse gases and climate change in the energy industry in particular, and diversity and inclusion initiatives and governance standards among companies more generally. The SEC, for example, promulgated new rules in 2024 that require disclosure of various specific risks related to climate but promptly issued an order staying their applicability pending resolution of legal challenges. The growing emphasis on ESG may lead the investment community to screen our ESG performance before investing in our common stock or debt securities or lending to us. Over the past few years there also has been an acceleration in investor demand for ESG investing opportunities, and many large institutional investors have committed to increasing the percentage of their portfolios that are allocated towards ESG-focused investments. As a result, there has been a proliferation of ESG-focused investment funds seeking ESG-oriented investment products.

If we are unable to meet the ESG standards or investment or lending criteria set by these investors and funds, we may lose investors, investors may allocate a portion of their capital away from us, our cost of capital may increase, the price of our common stock may be negatively impacted, and our reputation may be negatively affected.

Cybersecurity risk management is part of the Company’s overall enterprise risk management program. Our cybersecurity risk management program is designed to provide a framework for handling cybersecurity threats and incidents, including those associated with the use of third-party services and service providers. This framework includes steps for assessing a cybersecurity threat’s severity and source, including whether the cybersecurity threat is associated with a third-party service provider, implementing cybersecurity countermeasures and threat mitigation strategies, and informing management and our Board of material cybersecurity threats and incidents. To prevent and detect material cybersecurity incidents, our framework further includes, among other things, ongoing security awareness training for employees, regular cybersecurity risk and vulnerability assessments, and mechanisms to detect and monitor unusual network activity. We recognize the complex and evolving nature of cybersecurity threats and engage with various third-party service providers, including cybersecurity assessors and consultants, to evaluate and test our cybersecurity risk management systems. This enables us to leverage knowledge and insights to align our cybersecurity strategies and processes with best practices for our industry and size.

Our Board is ultimately responsible for overseeing our risk management, including cybersecurity risk management. Management is responsible for identifying, considering, and assessing material cybersecurity risks on an ongoing basis, establishing processes to ensure that such potential cybersecurity risk exposures are monitored, implementing appropriate mitigation measures, and maintaining cybersecurity programs. Our cybersecurity programs are under the direction of our Principal Financial Officer, who receives reports from our cybersecurity consultants and monitors the prevention, detection, mitigation, and remediation of cybersecurity incidents. Any significant cybersecurity incidents are reported to our independent Audit Committee and ultimately to our Board. There were no such cybersecurity incidents or threats that have materially impacted our business or operations. Management presents an assessment of our cybersecurity processes, procedures, and testing results to the Audit Committee at least annually.

Despite our efforts, we cannot eliminate all risks from cybersecurity threats nor provide assurances that we have not experienced an undetected cybersecurity incident. For more information about these risks, please see discussion captioned “Our business could be negatively affected by security threats. A cyber-attack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation, and/or financial loss.” in Item 1A. Risk Factors.

Information regarding our properties is included in Item 1. Business above and in Note 4, “Property and Equipment” to our consolidated financial statements in Item 8. Consolidated Financial Statements and Supplementary Data, which information is incorporated herein by reference.

See Note 10, “Commitments and Contingencies” to our consolidated financial statements in Item 8. Consolidated Financial Statements and Supplementary Data for a description of any legal proceedings, which is incorporated herein by reference.

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 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.

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 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.

Our non-operated interests in the Chaveroo oilfield consist of a 50% net working interest, with an average associated 41% revenue interest, in approximately 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”). See “Chaveroo Oilfield Participation Agreement” below for further information.

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 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 43,000 net acres (approximately 93% 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 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.

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 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. The 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 9, 2024, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable September 30, 2024.

SCOOP/STACK Acquisitions

On February 12, 2024, we closed the acquisitions of certain non-operated oil and natural gas assets in the SCOOP and STACK plays in central Oklahoma (the “SCOOP/STACK Acquisitions”) from Red Sky Resources III, LLC, Red Sky Resources IV, LLC, and Coriolis Energy Partners I, LLC. After taking into account customary closing adjustments and an effective date of November 1, 2023, total combined cash consideration for the SCOOP/STACK Acquisitions was approximately $39.2 million, which includes $43.9 million paid at closing less purchase price adjustments totaling approximately $4.7 million related to net cash flows earned on the properties from the effective date to the closing date.

The acquired assets consist of an average net working interest of approximately 2.6% in 253 producing wells in the SCOOP and STACK plays of the Anadarko Basin in Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties, Oklahoma. The acquisitions also include approximately 4,200 net acres (approximately 96% held by production) with approximately 300 associated potential drilling opportunities.

Senior Secured Credit Facility

On February 12, 2024, we entered into an amendment to the Senior Secured Credit Facility. This amendment required that we 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 25% of expected crude oil and natural gas production each month over that period. We have the option to choose whether to hedge 40% of expected crude oil production or 25% of expected crude oil and natural gas production.

Appointment of Chief Accounting Officer

On December 18, 2023, we announced that the Board of Directors approved the appointment of Kelly M. Beatty as Chief Accounting Officer, effective January 1, 2024. Ms. Beatty has been serving as Principal Accounting Officer since December 2022 and has served as the Company’s Controller since February 2022.

Share Repurchase Program

In November 2023, 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, 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. These shares were subsequently cancelled. We may enter into additional Rule 10b5-1 plans in the future, the terms of which will be approved by the Board of Directors.

Chaveroo Oilfield Participation Agreement

On September 12, 2023, we entered into a participation agreement (the “Participation Agreement”) with PEDEVCO for the joint development of the Chaveroo oilfield, a conventional oil-bearing San Andres field located in Chaves and Roosevelt Counties, New Mexico (the “Chaveroo Field”).

Pursuant to the Participation Agreement, we have the right, but not the obligation, to elect to participate in drilling locations on approximately 16,000 gross leasehold acres consisting of all leasehold rights from surface to the base of the San Andres formation, where PEDEVCO currently holds leasehold interest. We have agreed to pay PEDEVCO $450 per acre to acquire a 50% working interest share in the leases associated with the locations that we choose to participate in. The Participation Agreement initially includes up to 80 gross drilling locations across twelve development blocks. We have entered into a standard operating agreement with PEDEVCO serving as the operator with respect to the development of the properties. The Participation Agreement includes customary representations and warranties of the parties and other terms and conditions that are standard in such participation agreements.

As of June 30, 2024, we have incurred approximately $0.8 million in exchange for a 50% working interest share in approximately 1,600 net acres, associated with five development blocks. As of June 30, 2024, we have participated in the drilling and completion of the first development block which consisted of three gross (1.5 net) wells. Refer to Capital Expenditures below for a further discussion of Chaveroo drilling and completion activities since entering into the Participation Agreement.

Proved Reserves

The following table is a summary of our proved reserves as of June 30, 2024 and 2023:

Proved oil equivalent reserves as of June 30, 2024 were 31.8 MMBOE, a 0.6 MMBOE, or 1.9%, increase from the previous year of 31.2 MMBOE. The net increase in total proved reserves was primarily due extensions of 4.8 MMBOE primarily in Chaveroo Field and SCOOP/STACK as well as 3.2 MMBOE of reserves purchased in our SCOOP/STACK acquisition. These increases are partially offset by production of 2.5 MMBOE and net negative revisions of 4.9 MMBOE. Net negative revisions of 4.9 MMBOE are primarily due to declines in SEC trailing 12-month pricing, especially for natural gas reserves where the price per MMBTU declined 51.5% from the prior year, as well as impacting the late-in-life economic limits of production.

The Standardized Measure for proved reserves decreased 30.1% to $166.6 million, primarily due to decreases in the SEC mandated trailing 12-month average first day of the month prices for oil and natural gas and the price received for our NGLs; sales of oil, natural gas and NGLs produced during the period; and decreases in reserves estimates partially offset by extensions in Chaveroo Field and SCOOP/STACK and our SCOOP/STACK Acquisition. Prices decreased from $83.23 per barrel of oil, $4.78 per MMBtu of natural gas and $33.71 per barrel of NGLs at June 30, 2023 to $79.45 per barrel of oil, $2.32 per MMBtu of natural gas and $23.86 per barrel of NGLs at June 30, 2024. Our proved reserves consist of 37% oil, 41% natural gas, and 22% NGLs; 75.6% are classified as proved developed producing and 24.4% 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, 99.2, and 99.3 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 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 gas prices not only decrease our revenues, but an extended decline in oil or gas prices may affect planned capital expenditures and the oil and natural gas reserves that we can economically produce. Lower oil and 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.

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

Given the dynamic nature of these events, we cannot reasonably estimate the period of time that these market conditions will persist; predict the broader impact of liquidity concerns around financial institutions; the impact to long-term cost of capital or economic growth as a result of the Federal Reserve’s policies; or the impact on the commodity prices that we realize.

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 capital expenditures and present alternative plans as necessary.

Liquidity and Capital Resources

As of June 30, 2024, we had $6.4 million in cash and cash equivalents and $39.5 million outstanding borrowings on our Senior Secured Credit Facility compared to $11.0 million in cash and cash equivalents and no borrowings outstanding on our Senior Secured Credit Facility at June 30, 2023. Our primary sources of liquidity and capital resources during the year ended June 30, 2024 were cash provided by operations as well as net borrowings under our Senior Secured Credit Facility. Our primary uses of liquidity and capital resources for the year ended June 30, 2024 were our SCOOP/STACK Acquisition, cash dividend payments to our common stockholders, and development capital expenditures, primarily at Chaveroo oilfield where we participated in the drilling of three gross (1.5 net) wells. As of June 30, 2024, working capital was $5.9 million, a decrease of $3.0 million from working capital of $8.9 million as of June 30, 2023.

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 June 30, 2024. The Senior Secured Credit Facility is secured by substantially all of our oil and natural gas properties and matures on April 9, 2026.

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 years ended June 30, 2024 and 2023, the weighted average interest on our borrowings was 8.12% and 5.25%, 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 June 30, 2024, we were in compliance with all covenants under the Senior Secured Credit Facility.

On February 12, 2024, we entered into an amendment to the Senior Secured Credit Facility. This amendment required that we 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 25% of expected crude oil and natural gas production each month over that period. We have the option to choose whether to hedge 40% of expected crude oil production or 25% of expected crude oil and natural gas production.

On May 5, 2023, we entered into the Tenth Amendment to the Senior Secured Credit Facility. This amendment, among other things, extended the maturity of our Senior Secured Credit Facility to April 9, 2026, converted our benchmark interest rate from LIBOR to SOFR plus a credit spread adjustment of 0.05%, and modified the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, to $95.0 million. We are required to enter into hedges on a rolling 12-month basis when the borrowings under the Senior Secured Credit Facility exceed 25% of the Margined Collateral Value. The required amount of hedged oil and natural gas production is related to the amount of borrowings outstanding. At each redetermination, our Margined Collateral Value takes into account the estimated value of our oil and natural gas properties, proved developed reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria.

On February 7, 2022, we entered into the Ninth Amendment to the Senior Secured Credit Facility. This amendment, among other things, modified the definition of utilization percentage related to the required hedging covenant such that for the purposes of determining the amount of future production to hedge, the utilization of the Senior Secured Credit Facility will be based on the Margined Collateral Value, as amended above, to the extent it exceeds the borrowing base then in effect. This amendment also required us to enter into hedges for the 12-month period ending February 2023, covering 25% of expected oil and natural gas production over that period.

On November 9, 2021, we entered into the Eighth Amendment to the Senior Secured Credit Facility. This amendment, among other things, increased the borrowing base to $50.0 million and added a hedging covenant whereby we must hedge a certain amount of our future production on a rolling 12-month basis when 25% or more of the borrowing base is utilized. The hedging covenant was amended in subsequent amendments, as discussed above.

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.

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 June 30, 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.

Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 43 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 9, 2024, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on September 20, 2024 and payable on September 30, 2024.

On September 8, 2022, our Board of Directors approved a share repurchase program, under which we are authorized to repurchase up to $25.0 million of our common stock in the open market through December 31, 2024. We intend to fund any repurchases from working capital and cash provided by operating activities. 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 is complimentary to the existing dividend policy and is a tax efficient means to further improve shareholder return.

In December 2022, we entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan included a 30-day cooling off period that did not allow repurchases to commence until January 2023. The plan was effective until June 30, 2023 and had a maximum authorized amount of $5.0 million over that period. During the year ended June 30, 2023, 0.6 million shares of our common stock were repurchased under the plan at a total cost of approximately $3.9 million, including incremental direct transaction costs. These treasury shares were subsequently cancelled.

In November 2023, 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, 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. These shares were subsequently cancelled. We may enter into additional Rule 10b5-1 plans in the future, the terms of which will be approved by the Board of Directors.

Capital Expenditures

For the year ended June 30, 2024, we incurred $12.3 million on development capital expenditures across our portfolio of assets, excluding acquisitions. At the Chaveroo Field, we purchased undeveloped acreage and also participated in drilling and completion of three gross (1.5 net) wells. First production on the three gross wells at Chaveroo Field occurred at the beginning of February 2024. We also participated in the drilling and completion of two new wells in the Delhi Field that came online during the first fiscal quarter of 2024. Since acquiring our SCOOP/STACK properties, we have participated in the drilling and completion of 14 gross wells.

Based on discussions with our operators, we expect capital workover projects to continue in all the fields. 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 the next 12 months include bringing approximately 13 gross wells online at our SCOOP/STACK properties, the drilling and completion of four new wells at Chaveroo Field, and the drilling and completion of one new well at Delhi Field Test Site V.

As of June 30, 2024, our PUD reserves included 7.7 MMBOE of reserves and approximately $90.5 million of future development costs primarily associated with the SCOOP/STACK, Chaveroo Field, and Williston Basin properties, and Test Site V at Delhi Field.

Funding for our anticipated capital expenditures over the near-term is expected to be met from cash flows from operations and current working capital, 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, 2024 were $79.45 per barrel of oil, $2.32 per MMBtu of natural gas and $23.86 per barrel of NGLs. As of June 30, 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 June 30, 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 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, 2024, while all other factors remained constant, would not have generated an impairment.

Overview of Cash Flow Activities

Cash provided by operating activities decreased $28.5 million during the fiscal year ended June 30, 2024 compared to fiscal year ended June 30, 2023 primarily due to a decrease in revenue. Total revenues decreased $42.6 million as compared to the prior year primarily due to lower commodity prices coupled with lower sales volumes. Our average realized price per barrel of oil equivalent (“BOE”) decreased $15.00, or 30.3% from the prior year period. Refer to “Results of Operations” below for further information.

Cash used in investing activities for the year ended June 30, 2023 increased $42.6 million from the prior year primarily due to the acquisition of our SCOOP/STACK properties in February 2024 together with an increase in capital expenditures related to the drilling and completion of three gross (1.5 net) new wells in the Chaveroo Field and to a lesser extent, drilling and completion expenditures at Delhi Field and SCOOP/STACK. As of the year ended June 30, 2024, we have paid approximately $38.7 million for the SCOOP/STACK Acquisitions and have accrued purchase price adjustments of $0.5 million related to net cash flows due on the properties from the effective date to the closing date to arrive at a net purchase price of $39.2 million.

Net cash flows provided by financing activities for the year ended June 30, 2024 were $22.3 million compared to net cash flows used in financing activities of $41.5 million for the year ended June 30, 2023. In the current year period, we had net borrowings of $39.5 million under our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions, $16.0 million cash dividends paid to our common stockholders together with $0.8 million paid to repurchase shares of common stock under our share repurchase plan. In the prior year period, we had repayments totaling $21.3 million of borrowings outstanding under our Senior Secured Credit Facility, $16.1 million in cash dividends paid to our common stockholders and $3.9 million paid to repurchase shares of common stock under our share repurchase program.

Results of Operations

Years Ended June 30, 2024 and 2023

We reported net income of $4.1 million and $35.2 million for the years ended June 30, 2024 and 2023, 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 $85.9 million and $128.5 million for the fiscal years ended June 30, 2024 and 2023, respectively. The decrease in revenues is primarily due to the decrease in our average realized price per BOE coupled with a decrease in our sales volumes. Our average realized commodity price (excluding the impact of derivative contracts) decreased approximately $15.00 per BOE, or 30.3%, for the fiscal year ended June 30, 2024 compared to June 30, 2023. 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. Realized natural gas prices decreased 62.7% from the prior fiscal year, which was the largest portion of the driver of the decrease in revenues. This was partially attributed to the prior fiscal year benefit of strong natural gas price differentials received at the Jonah Field where we realized an average natural gas price of $10.63 per MCF in the prior fiscal year compared to $3.55 for the current fiscal year. Average daily equivalent production decreased 4.4% from 7,104 BOEPD to 6,790 BOEPD in the current fiscal year as a result of natural production declines in our properties combined with operational issues and downtime at certain properties throughout the year. As of June 30, 2024, due to low natural gas prices, certain wells at Barnett Shale are shut-in and remain offline which has continued to negatively impact production volumes. The overall decrease in production was partially offset by the acquisitions of non-operated working interests in the SCOOP/STACK in February 2024 and first production at our wells in the Chaveroo Field in early February 2024, which collectively increased production for the year ended June 30, 2024 by approximately 601 BOEPD. Combined production at these two fields is primarily oil, thus increasing our oil volumes year over year.

Lease Operating Costs

Ad valorem and production taxes were $5.3 million and $8.2 million for the years ended June 30, 2024 and 2023, respectively. On a per unit basis, ad valorem and production taxes were $2.13 per BOE and $3.15 per BOE for the years ended June 30, 2024 and 2023, respectively. The decrease in ad valorem and production taxes is primarily due to decreases in our realized oil and natural gas prices as well as decreased production volumes described above as production taxes are based on sales at the wellhead.

The following table summarizes CO2 costs per Mcf and CO2 volumes for the years ended June 30, 2024 and 2023. CO2 purchase costs are for the Delhi Field. Under our contract with the Delhi Field operator, purchased CO2 is priced at 1% of the realized oil price in the field per Mcf, plus sales taxes and transportation costs as per contract terms.

The $3.1 million decrease in CO2 costs for the fiscal year ended June 30, 2024 was primarily due to a 41.0% decrease in purchased CO2 volumes combined with a 2.0% decrease in CO2 costs per MCF, which was driven by a decrease in our average realized oil price. In February 2024, CO2 purchased volumes were suspended due to maintenance on the CO2 pipeline. CO2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. We do not have any ownership in the CO2 pipeline which is owned and operated by Denbury. On a per unit basis, CO2 costs were $1.71 per BOE and $2.84 per BOE for the years ended June 30, 2024 and 2023, respectively. CO2 purchases are expected to restart in early second quarter of fiscal 2025.

Other lease operating costs decreased $5.3 million, or 12.0%, compared to the prior fiscal year primarily due to lower production combined with the lower commodity price environment. On a per unit basis, other lease operating costs decreased to $15.59 per BOE in the current year from $16.97 per BOE in the prior year. The largest decrease in other lease operating costs is at our Barnett Shale properties and the Delhi Field. At the Barnett Shale, significant cost savings efforts are being prioritized due to the lower realized natural gas prices and the shut-in of certain low margin wells at current natural gas prices. We are incurring lower operating costs in all cost categories, especially lower water hauling costs and lower gathering, transportation and processing charges. At Delhi Field, we have seen lower electricity charges due to lower commodity prices and decreased electrical demand due the installation of heat exchangers. These decreases are partially offset by increases in other lease operating costs associated with our acquisitions of non-operated working interests in the SCOOP/STACK in February 2024 and first production at our wells in the Chaveroo Field in early February 2024.

Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased $5.5 million or 41.6% from $13.1 million for the fiscal year ended June 30, 2023 to $18.6 million for the fiscal year ended June 30, 2024 primarily due to an increase in the depletion rate. On a per unit basis, depletion expense was $7.49 per BOE and $5.07 per BOE for the fiscal years ended June 30, 2024 and 2023, respectively. The depletion rate of our unit of production calculation increased primarily due to an increase in our depletable base due to our SCOOP/STACK Acquisitions and capital expenditures since the prior year period.

General and Administrative Expenses

General and administrative expenses for the fiscal year ended June 30, 2024 decreased $0.4 million, or 5.6%, to $7.5 million compared to $7.9 million for the fiscal year ended June 30, 2023. The decrease primarily relates to lower consulting fees totaling approximately $0.3 million related to our search for a CEO in the prior year period. On a per unit basis, general and administrative expenses were $3.02 per BOE and $3.06 per BOE for the years ended June 30, 2024 and 2023, respectively.

Stock-based Compensation Expenses

Stock-based compensation increased $0.5 million to $2.1 million for the year ended June 30, 2024 compared to $1.6 million the prior period due primarily to the addition of new personnel and the associated new awards granted during the current year period to all staff and directors.

Net Gain (Loss) on Derivative Contracts

Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. 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.

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

As a result of our acquisitions during fiscal years 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 commodity prices since entering into the hedges and the continued increase in forward commodity prices resulted in a realized loss on hedges for the current year and an unrealized loss on the mark-to-market of our hedges. As of June 30, 2024, we had $0.8 million derivative assets, $0.6 million of which was classified as current, and a $1.7 million derivative liability, $1.2 million of which was classified as current.

Interest Expense

Interest expense increased $1.0 million during the fiscal year ended June 30, 2024 compared to fiscal year 2023 primarily due to borrowings drawn on our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions during the current year. In addition, the weighted average interest rate on our borrowings increased to 8.12% for the fiscal year ended June 30, 2024 compared to 5.25% for fiscal year 2023.

Income tax (expense) provision

For the year ended June 30, 2024, we recognized income tax expense of $1.4 million on net income before income taxes of $5.5 million compared to an income tax expense of $10.1 million on net income before income taxes of $45.3 million for the year ended June 30, 2023. The effective tax rates were 25.8% and 22.2% for the years ended June 30, 2024 and 2023, respectively. The effective tax rate increased compared to the prior year period as projected state income taxes have become a larger component of our overall income tax expense during the period.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires that we select certain accounting policies and make estimates and assumptions that affect the reported amounts of the assets, liabilities, and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported amounts of revenues and expenses during the reporting period. These policies, together with our estimates, have a significant effect on our consolidated financial statements. Our significant accounting policies are included in Note 1, “Summary of Significant Events and Accounting Policies” to our consolidated statements in Item 8. Following is a discussion of our most critical accounting estimates, judgments, and uncertainties that are inherent in the preparation of our consolidated financial statements.

Oil and Natural Gas Properties. Companies engaged in the production of oil and natural gas are required to follow accounting rules that are unique to the oil and natural gas industry. We apply the full cost accounting method for our oil and natural gas properties as prescribed by SEC Regulation S-X Rule 4-10. Under this method of accounting, the costs of unsuccessful and successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration, and development activities but does not include any costs related to production, general corporate overhead, or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded represent investments in unevaluated properties. We exclude these costs until the property has been evaluated. Costs are transferred to the full cost pool as the properties are evaluated. As of June 30, 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, 2024, 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, 2024 of 10% would affect depletion, depreciation, and amortization expense by approximately $0.5 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 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.

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 2024 and 2023, 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 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%, which includes a 0.05% credit spread adjustment from LIBOR, 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.

Disclosure Controls and Procedures

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 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 Securities and Exchange Commission 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 of the end of the period covered by this report. Based on this evaluation, our Principal Executive Officer and Principal Financial Officer concluded that 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 Securities and Exchange Commission rules and forms.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) as a process designed by, or under the supervision of, our principal executive and principal financial officers and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Generally accepted accounting principles include those policies and procedures that:

• pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;
• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and
• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of management, including the Principal Executive Officer and the Principal Financial Officer, an evaluation was conducted on the effectiveness of our internal control over financial reporting based on criteria established in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Management concluded that we maintained effective internal control over financial reporting as of June 30, 2024.

The effectiveness of the Company’s internal controls over financial reporting as of June 30, 2024, has been audited by Moss Adams LLP., an independent registered public accounting firm, as stated in their report.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the three months ended June 30, 2024 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.