Table of Contents

GLOSSARY OF SELECTED PETROLEUM INDUSTRY TERMS

​

iv

Table of Contents

v

Table of Contents

vi

Table of Contents

​

​

vii

Table of Contents

PART I

Item 1. Business

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.

1

Table of Contents

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. 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 shares were subsequently cancelled. These treasury 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:

​

2

Table of Contents

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. For the year ended June 30, 2023, our average net daily production from the Jonah Field properties was 1.9 MBOEPD consisting of 90% natural gas, 5% NGLs, and 5% oil. 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

3

Table of Contents

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. For the year ended June 30, 2023, our average net daily production from the Jonah Field properties was 1.9 MBOEPD consisting of 90% natural gas, 5% NGLs, and 5% oil. 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”). The properties are operated by Jonah Energy (“Jonah”), an established operator in the geographic region.

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”). The properties are operated by Foundation Energy Management (“Foundation”), an established operator in the geographic region.

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 approximately 5,900 gross acre 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 vast 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.

4

Table of Contents

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

5

Table of Contents

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

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. Our Board of Directors also has oversight of our reserve estimation process and contains a Reserves Committee with 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,

6

Table of Contents

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:

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 this time, operators of our properties at 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

7

Table of Contents

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.

8

Table of Contents

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:

9

Table of Contents

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.

10

Table of Contents

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:

​

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. In the 8 Table of ContentsJonah 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. We do not currently market our share of oil, natural gas, or NGLs production from the Williston Basin, the Barnett Shale, the Hamilton Dome Field, or the Delhi 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

11

Table of Contents

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.While there are many different types of derivative instruments available, historically we have used costless collars 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. Costless collar agreements are put and call options used to establish 9 Table of Contentsfloor 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.

​

12

Table of Contents

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:

​