Crescent Energy (CRGY) 10-K2022 FY Annual report

Crescent Energy Company ("we," "us," or the "Company") files annual, quarterly and current reports with the SEC. The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, including the Company.

Investors can also access financial and other information via our website at www.crescentenergyco.com. The Company makes available, free of charge through the website, copies of Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to such reports, our environmental, social, and governance (“ESG”) reports and all reports filed by executive officers and directors under Section 16 of the Exchange Act reporting transactions in the Company's securities. Access to these reports is provided as soon as reasonably practical after such reports are electronically filed with the SEC. In addition to its reports filed or furnished with the SEC, the Company publicly discloses material information from time to time in its press releases, in publicly accessible conferences and investor presentations, and through its website. Information contained on or connected to our website which is not directly incorporated by reference into this Annual Report on Form 10-K (this "Annual Report") should not be considered part of this report or any other filing made with the SEC.

Crescent Energy Company's website also can be used to access copies of charters for its board committees, including the Nominating & Governance Committee, Compensation Committee and Audit Committee, and governance documents, including our Corporate Governance Guidelines and our Code of Business Conduct and Ethics, free of charge. Additionally, we intend to make future Annual Reports, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports as soon as reasonably practical after the filing of such reports available on our website. Our website is maintained at www.crescentenergyco.com. While the Company recommends that you view Crescent Energy Company's website, the information available on our website is not part of this report and is not incorporated herein by reference.

You may request a copy of filings other than an exhibit to a filing unless that exhibit is specifically incorporated by reference into that filing, at no cost by writing or calling Crescent Energy Company, 600 Travis Street, Suite 7200, Houston, TX 77002 (telephone number: 713-337-4600).

The information in this Annual Report contains or incorporates by reference information that includes or is based upon "forward-looking statements" within the meaning of Section 27A of the Securities Act , and Section 21E of the Exchange Act. All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, increases in oil, natural gas and natural gas liquids (“NGL”) production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could,” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

We caution you that these forward-looking statements are subject to all of the risks and uncertainties incident to the development, production, gathering and sale of oil, natural gas and NGLs, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability and cost of drilling and production equipment and services, project construction delays, environmental risks, drilling and other operating risks, lack of availability or capacity of midstream gathering and transportation infrastructure, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described under “Risk Factors.”

Reserve engineering is a process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact way. The accuracy of any reserve estimates depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development program. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Annual Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report.

The following is a summary of the principal risks that could adversely affect our business, operations and financial results. Please refer to "Part I., Item 1A. Risk Factors" of this Annual Report below for additional discussion of the risks summarized in this Risk Factors Summary.

"April 2021 Exchange” means the redemption by certain of Independence’s consolidated subsidiaries of the noncontrolling equity interests held in such subsidiaries by certain third-party investors in exchange for membership interests in Independence in April 2021.

“ARO” means an asset retirement obligation.

“Bbl” means 42 U.S. gallons liquid volume per stock tank barrel.

“BLM” means the federal Bureau of Land Management.

"Board" means the Board of Directors of Crescent Energy Company.

“Boe” means barrels of oil equivalent.

“Btu” means British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water one degree Fahrenheit.

“CAA” means the federal Clean Air Act, as amended, and the rules and regulations promulgated thereunder.

“CARB” means the California Air Resources Board.

“CERCLA” means the federal Comprehensive Environmental Response, Compensation, and Liability Act, as amended, and the rules and regulations promulgated thereunder.

“CFTC” means the Commodity Futures Trading Commission.

“Class A Common Stock” means the shares of Class A common stock, par value $0.0001 per share, of the Company.

“Class B Common Stock” means the shares of Class B common stock, par value $0.0001 per share, of the Company.

“Code” means the Internal Revenue Code of 1986, as amended.

“Company Group” means the Company and each of its subsidiaries (other than OpCo and its subsidiaries).

"Contango" means Contango Oil & Gas Company, a Texas corporation.

"Contango Incentive Plan" means the Contango Oil & Gas Company Third Amended and Restated 2009 Incentive Compensation Plan.

“Contango Merger” means the merger of IE C Merger Sub Inc., a Delaware corporation, with and into Contango, with Contango surviving the merger as a direct wholly owned corporate subsidiary of the Company.

"Contango PSU Award" means each award of performance stock units (whether vested or unvested) granted under the Contango Incentive Plan that were outstanding immediately prior to the effective time of the Contango Merger.

“CWA” means the Federal Water Pollution Control Act, as amended, and the rules and regulations promulgated thereunder.

“Decontrol Act” means the Natural Gas Wellhead Decontrol Act, effective January 1, 1993.

“DJ” means Denver Julesburg.

“Dodd-Frank” means the Dodd-Frank Wall Street Reform and Consumer Protection Act.

“DOI” means the U.S. Department of the Interior.

“DOT” means the U.S. Department of Transportation.

“EHS” means Environment, Health and Safety.

“EIGF II” means Energy Income and Growth Fund II, formed in 2018 as a KKR energy investment fund.

“EPA” means the U.S. Environmental Protection Agency.

“Equity Incentive Plan” means the Crescent Energy Company 2021 Equity Incentive Plan.

“ESA” means the federal Endangered Species Act, as amended, and the rules and regulations promulgated thereunder.

“ESG” means Environmental, Social and Governance.

“Exchange Act” means the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.

“FERC” means the Federal Energy Regulatory Commission.

“FRA” means the Federal Railroad Administration.

“FTC” means the Federal Trade Commission.

“FWS” means the U.S. Fish and Wildlife Service.

“GAAP” means U.S. generally accepted accounting principles.

“GHGs” means greenhouse gases.

“ICA” means the Interstate Commerce Act of 1887 and the rules and regulations promulgated thereunder.

“Independence” means Independence Energy LLC, a Delaware limited liability company.

“IRS” means the United States Internal Revenue Service.

“IT” means Information Technology.

“KKR” means the Manager and its affiliates, which includes the Preferred Stockholder and EIGF II.

“KKR Funds” means EIGF II and/or other KKR funds.

“KKR Group” means KKR & Co. Inc and its subsidiaries.

“LCFS” means low carbon fuel standard.

“M" means in thousands.

"MM" means in millions.

“Management Agreement” means the management agreement, dated as of December 7, 2021, by and between the Company and the Manager, whereby the Manager manages the business and operations of the Company and its subsidiaries and provides the executive management team for the benefit of the Company and its subsidiaries.

“Manager” means KKR Energy Assets Manager LLC, a Delaware limited liability company.

"Manager Incentive Plan” means the Crescent Energy Company 2021 Manager Incentive Plan.

“MBTA” means the Migratory Bird Treaty Act, as amended, and the rules and regulations promulgated thereunder.

“MBbls” means thousand barrels of oil or NGL.

“MBoe” means thousand Boe.

“Mcf” means thousand cubic feet of natural gas.

"Merger Transactions" means the transactions contemplated by the Transaction Agreement, which include the merger of Independence with and into OpCo, the Contango Merger, the subsequent merger of Contango with and into IE L Merger Sub LLC, with L Merger Sub surviving the merger as a wholly owned subsidiary of the Company, which we describe as the “Merger”, and the subsequent contribution of such surviving subsidiary by the Company to OpCo.

“MMBoe” means million Boe.

“MMBtu” means million British thermal units.

“MMcf” means million cubic feet of natural gas.

“NAAQS” means National Ambient Air Quality Standard.

“NEPA” means the National Environmental Policy Act, as amended, and the rules and regulations promulgated thereunder.

"Non-Economic Series I Preferred Stock” means the 1,000 shares of the Company's Preferred Stock that are designated as “Series I Preferred Stock,” which have no economic rights.

“NGA” means the Natural Gas Act of 1938 and the rules and regulations promulgated thereunder.

“NGFS” means the Network for Greening the Financial System.

“NGPA” means the Natural Gas Policy Act of 1978, as amended, and the rules and regulations promulgated thereunder.

“Noncontrolling Interest Carve-out” means the redemption in May 2021 of certain noncontrolling equity interests in exchange for a third-party investor’s proportionate share of the underlying oil and natural gas interests held by its consolidated subsidiaries. In August 2020, in connection with the Independence Reorganization, certain interests in our consolidated subsidiaries owned by a third-party investor were not contributed to the Predecessor. These interests were reclassified from members’ equity to noncontrolling interest as of the date of the Independence Reorganization and all income and loss attributable to these interests is recorded as net income (loss) attributable to noncontrolling interests from the date of the Independence Reorganization. In May 2021, these noncontrolling equity interests were redeemed in exchange for the third-party investor’s proportionate share of the underlying oil and natural gas interests held by its consolidated subsidiaries.

“NWPR” means the Navigable Waters Protection Rule, as amended.

“NYMEX” means the New York Mercantile Exchange.

“Henry Hub Index” means the major exchange for pricing natural gas futures on the New York Mercantile Exchange.

“NYSE” means the New York Stock Exchange.

“oil equivalent” means natural gas is converted to a crude oil equivalent at the ratio of six Mcf of natural gas to one Boe.

“OPA” means the federal Oil Pollution Act of 1990, as amended, and the rules and regulations promulgated thereunder.

“OpCo” means Crescent Energy OpCo LLC (f/k/a IE OpCo LLC), a Delaware limited liability company.

“OpCo LLC Agreement” means the Amended and Restated Limited Liability Company Agreement of OpCo.

“OpCo Units” means the units representing economic limited liability company interests in OpCo.

“OPEC” means the Organization of Petroleum Exporting Countries.

“OSHA” means the federal Occupational Safety and Health Act, as amended, and the rules and regulations promulgated thereunder.

“PDP” means proved developed producing.

“PHMSA” means the Pipeline and Hazardous Materials Safety Administration.

“Preferred Stockholder” means Independence Energy Aggregator LP, the initial holder of the Non-Economic Series I Preferred Stock, and, as applicable, any successor thereto.

“PT Independence” means PT Independence Energy Holdings, LLC, a Delaware limited liability company.

“PUD” means proved undeveloped reserve.

“PV-0 value” means the present value of estimated future oil and gas revenues, net of estimated direct expenses, discounted at an annual discount rate of 0% used to estimate the present value of proved oil and natural gas reserves.

“PV-10 value” means the present value of estimated future oil and gas revenues, net of estimated direct expenses, discounted at an annual discount rate of 10% used to estimate the present value of proved oil and natural gas reserves.

“RCRA” means the federal Resource Conservation and Recovery Act, as amended, and the rules and regulations promulgated thereunder.

“Redemption Right” means the right of a holder of OpCo Units (other than a member of the Company Group) pursuant to the OpCo LLC Agreement to cause OpCo to redeem all or a portion of its OpCo Units for, at the election of OpCo, (a) shares of Class A Common Stock at a redemption ratio of one share of Class A Common Stock for each OpCo Unit redeemed, or (b) an approximately equivalent amount of cash as determined pursuant to the terms of the OpCo LLC Agreement. In connection with such redemption, a corresponding number of shares of Class B Common Stock will be cancelled.

“Revolving Credit Facility” means the credit agreement, by and between Independence Energy Finance LLC (n/k/a Crescent Energy Finance LLC), Wells Fargo Bank, N.A., as administrative agent, the guarantor parties thereto and the lender parties thereto.

“SASB” means the Sustainability Accounting Standards Board.

“SDWA” means the federal Safe Drinking Water Act, as amended, and the rules and regulations promulgated thereunder.

“SEC” means the United States Securities and Exchange Commission.

“SEC Pricing” means the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning January 1, 2022 and ending December 1, 2022, adjusted by lease for market differentials (quality, transportation, fees, energy content, and regional price differentials). The SEC provides a complete definition of prices in “Modernization of Oil and Gas Reporting” (Final Rule, Release Nos. 33-8995; 34-59192).

“Securities Act” means the Securities Act of 1933, as amended, and the rules and regulations promulgated thereunder.

“Titan” means Titan Energy Holdings, LLC (f/k/a Liberty Energy LLC).

“Titan Acquisition” means the acquisition by Independence (n/k/a Crescent) of Titan.

“Transaction Agreement” means that certain Transaction Agreement, dated as of June 7, 2021, by and among Contango, Independence, the Company, OpCo, IE C Merger Sub Inc., a Delaware corporation, and IE L Merger Sub LLC, a Delaware limited liability company.

“TRC” means the Texas Railroad Commission.

“UIC” means the Underground Injection Control program administered by the SDWA.

“WTI” or “West Texas Intermediate” means a light crude oil produced in the United States with an American Petroleum Institute gravity of approximately 38 to 40 and the sulfur content is approximately 0.3%.

We are a well-capitalized U.S. independent energy company with a portfolio of low-decline assets in proven regions across the lower 48 states that generate substantial cash flow supported by a predictable base of production. Our core leadership team is a group of experienced investment, financial and industry professionals who continue to execute on the strategy we have employed since 2011. Our mission is to invest in energy assets and deliver better returns through strong operations and stewardship. We seek to deliver attractive risk-adjusted investment returns and predictable cash flows across cycles by employing our differentiated approach to investing in the oil and gas industry. Our approach employs a unique business model that combines an investor mindset and deep operational expertise to pursue a cash flow-based investment mandate focused on operated working interests with an active risk management strategy. Our Class A Common Stock trades on the NYSE under the symbol “CRGY.”

We pursue our strategy through the production, development and acquisition of oil, natural gas and NGL reserves. Our free cash flow-focused portfolio includes a balanced set of oil and natural gas assets in proven onshore U.S. basins with substantial existing production, a low decline rate and an acreage position that is 96% held by production as of December 31, 2022. As a result of this overall low decline profile, we require relatively minimal capital expenditures to maintain our production and cash flows. We have a robust inventory of attractive operated undeveloped locations, providing for optimal flexibility to maintain or grow our production base. While many operators in our industry have historically focused on the capital intensive pursuit of high production growth rates, our management team has a track record of selectively acquiring cash flow oriented assets, operating them more profitably and making disciplined, returns focused reinvestment decisions to drive free cash flow generation. Our portfolio is enhanced and complemented by our additional interests in mineral acreage and midstream infrastructure, which provide operational benefits and enhance our cash flow margins.

We have built a substantial portfolio of reserves, production, and cash flows and reinvestment opportunities. Our portfolio of assets:

The following diagram displays our simplified ownership structure:

Our asset base, which includes oil and natural gas assets in key proven onshore U.S. basins such as the Eagle Ford, Rockies, Barnett, Permian, and Mid-Con, is composed of producing properties with substantial production and hedged cash flow that are complemented by an extensive inventory of reinvestment opportunities across our undeveloped acreage. While many of our peers have historically outspent their cash flows in pursuit of production growth and left themselves particularly vulnerable to declines in commodity prices, we have an average reinvestment rate of approximately 40% of Adjusted EBITDAX since 2018.

Our PDP reserves as of December 31, 2022 have estimated average five-year and ten-year annual decline rates of approximately 13% and 10%, respectively, and an estimated 2023 PDP decline rate of 22%, based on forecasts used in our reserve reports. As a result of this low decline profile, we require relatively minimal capital expenditures to maintain our production and cash flows. Our properties located in the Eagle Ford, Rockies, and Barnett represent approximately 84% of our proved reserves as of December 31, 2022, and provide us with diversification from both a regional location and commodity price perspective, which provides us certain downside protection as it relates to commodity-specific pressures, isolated infrastructure constraints or severe weather events. Our Standardized Measure totaled $9.1 billion as of December 31, 2022. The table below illustrates the aggregate leasehold acreage positions, reserve volumes and weighted average decline profiles associated with our proved assets as of December 31, 2022.

We are a party to a Management Agreement with the Manager, that engages the Manager to provide certain management and investment advisory services to us and our subsidiaries. Our management team provides services to us pursuant to the Management Agreement.

The Manager is an indirect subsidiary of the KKR Group. The KKR Group is a leading global investment firm that offers alternative asset management as well as capital markets and insurance solutions.

Pursuant to the Management Agreement, the Manager has agreed to provide us with management services, including our full executive and corporate management teams, and other assistance, including with respect to strategic planning, risk management, identifying and screening potential acquisitions, identifying and analyzing ESG issues and providing such other assistance as we may require.

Through our integration with the KKR Group’s global platform, we believe that we benefit from: the power of the “KKR Brand;” KKR Capstone, which creates value by assisting with due diligence and identifying and delivering sustainable operational performance improvements within the KKR Group’s portfolio companies; KKR Global Macro and Asset Allocation, which assists with assessing the impact of macroeconomic factors on potential investments and helps identify market opportunities; KKR Capital Markets LLC ("KCM"), which assists with optimizing the capital structure of investments and underwrites and arranges debt, equity and other forms of financing for both KKR portfolio companies and independent clients, and KKR Public Affairs, which, together with the KKR Global Institute, provides insight into ESG, regulatory, geopolitical, and reputational issues, including experience working with key stakeholders, such as labor unions, industry and trade associations and non-governmental organizations.

We are a party to a Management Agreement pursuant to which we have engaged the Manager to manage the strategy, assets and day-to-day business and affairs of us and our subsidiaries, subject at all times to applicable law, the further terms and conditions set forth in the Management Agreement and to the supervision of our Board. Pursuant to the Management Agreement, the Manager will provide us with our executive management team and will manage our day-to-day operations. Additionally, pursuant to the Management Agreement:

Our portfolio includes low-decline oil and natural gas assets in proven regions across the United States, including in the Eagle Ford, Rockies, and Barnett. In addition to this geographic diversity, we believe that our portfolio of leasehold acreage is enhanced and complemented by our additional interests in mineral acreage and midstream infrastructure. We had leasehold interests in an aggregate 1.2 million net acres as of December 31, 2022, 1.0 million of which we were designated as operator. We are responsible for our pro rata share of capital expenditures and lease operating expenses for the operated and non-operated working interests within our leasehold acreage based on our percentage working interest and we are entitled to revenues derived from such interest based on our net revenue interest, which generally equals our working interest in such property less any royalties and production payments and any overriding royalty and net profits interests burdening the property.

In addition to our leasehold acreage, we own mineral and royalty interests. As of December 31, 2022, we owned mineral interests in 174 thousand gross acres and an overriding royalty interest in 125 thousand gross acres, both operated by large, well-capitalized oil and natural gas companies primarily in the Eagle Ford, Marcellus, Utica and Rockies. On our mineral acreage, all of which we have leased to other operators, we have typically retained a royalty interest, which is a cost-free percentage of production revenue that expires upon termination of the lease, at which time the entire mineral interest reverts to us. These interests entitle us to receive a royalty and overriding royalty interest on all production from such acreage with no additional future capital or operating costs required.

We own and operate a variety of midstream assets, which provide services to our upstream assets and other customers. These include:

The following table summarizes our estimated net proved reserves as of December 31, 2022 based on an evaluation prepared in accordance with SEC Pricing, including the provisions of the SEC rule regarding reserve estimation regarding a historical twelve month pricing average applied prospectively.

Our reserve estimates as of December 31, 2022 are primarily based on evaluations prepared by Ryder Scott Company, L.P., with respect to 98% of our total proved reserves, with the remaining 2% prepared by our internal technical staff. Our reserve estimates prepared as of December 31, 2021 were based on a combination of evaluations prepared or audited, as applicable, by the independent petroleum engineering firms of (a) Haas Petroleum Engineering Services, Inc., with respect to 34% of our total net proved reserves, (b) William M. Cobb and Associates, with respect to 24% of our total net proved reserves (c) Cawley, Gillespie & Associates, Inc. with respect to 23% of our total net proved reserves, and (d) Netherland, Sewell & Associates, Inc. with respect to 19% of our total net proved reserves, (together with Ryder Scott Company, L.P., the “Independent Reserve Engineers”), in each case in accordance with the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" (June 2019) promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. Our Independent Reserve Engineers were selected for their historical experience and geographic expertise in engineering similar resources. Our reserve estimation process is a collaborative effort coordinated by the lead reservoir engineers at each of our operating subsidiaries, who are petroleum engineers with an average of 18 years of reservoir and operations experience per person. This process is overseen by our Director of Corporate Reserves, who has over 16 years of experience in the estimation and evaluation of petroleum reserves. Our technical staff uses historical information for our properties such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs to formulate our reserves estimates. The preparation of our proved reserve estimates is completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

    

The technical person responsible for preparing our reserves estimates at December 31, 2022 from Ryder Scott Company, L.P. has over 44 years of industry experience. The technical persons responsible for preparing our reserve estimates at December 31, 2021 and their respective years of experience at that time were; (a) Haas Petroleum Engineering & Associates, Inc. had over 20 years of industry experience; (b) William M. Cobb and Associates had over 40 years of experience in the estimation and evaluation of reserves; (c) Cawley, Gillespie & Associates, Inc. had over 29 years of experience in the estimation and

evaluation of petroleum reserves; and (d) Netherland, Sewell & Associates, Inc. had over 20 years of experience in the estimation and evaluation of petroleum reserves.

Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, we and the Independent Reserve Engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available downhole and production data and well-test data.

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net cash flows are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See "Item 1A. Risk Factors" appearing elsewhere in this Annual Report.

With respect to the Independent Reserve Engineers that performed an audit of a portion of our reserves as of December 31, 2021, we provided to such Independent Reserve Engineers our public and internal engineering and geoscience technical data and analyses. Such Independent Reserve Engineers accepted without independently verifying the accuracy and completeness of the historical information and data furnished by us with respect to ownership interest, oil and natural gas production, well test data, commodity prices, operating and development costs and any agreements relating to current and future operations of the properties and sales of production. However, if in the course of its evaluations something came to their attention that brought into question the validity or sufficiency of any such information or data, the Independent Reserve Engineers did not rely on such information or data until they had satisfactorily resolved their questions relating thereto or had independently verified such information or data. In the course of their evaluations, the Independent Reserve Engineers prepared, for all of the audited properties, their own estimates of our reserves. The Independent Reserve Engineers reviewed their audit differences with us, and, as necessary, held meetings with us to review additional reserves work performed by our technical teams and any updated performance data related to the reserve differences. Such data was incorporated, as appropriate, by both parties into the reserve estimates. The Independent Reserve Engineers’ estimates, including any adjustments resulting from additional data, of those reserves and did not differ from our estimates by more than 10% in the aggregate. When such differences did not exceed 10% in the aggregate and the Independent Reserve Engineers was satisfied that the reserves were reasonable and that its audit objectives had been met, the Independent Reserve Engineers issued an unqualified audit opinion.

Our PUDs will be converted from undeveloped to developed as the applicable wells have been drilled or completed and have minimal capital remaining to bring the well onto production. The changes to our PUDs that occurred during the year are summarized in the table below:

Purchases of reserves in place of 26.0 MMBoe during the year ended December 31, 2022 primarily relate to PUD locations added as part of the Uinta Acquisition. Extensions and discoveries of 48.5 MMBoe primarily relate to extensions on our Eagle Ford asset. Revisions of previous estimates during the year ended December 31, 2022 were primarily due to increased expected future costs driven by inflation and a higher commodity price environment. Additionally, during the year ended December 31, 2022, we spent $209.0 million to convert 17.6 MMBoe to proved developed reserves.

All of such reserves are scheduled to be developed within five years from the date such locations were initially disclosed as PUD reserves. Our PUD reserves represent only reserves that are scheduled, based on such plan, to be developed within five years from the date such locations were initially disclosed as PUDs; however, our five-year development plan may not contemplate a uniform (i.e., 20% per year) conversion of PUD reserves. At December 31, 2022, we estimate that our future development costs relating to the development of PUD reserves are $451 million in 2023, $389 million in 2024 and $382 million in 2025, $245 million in 2026 and $181 million in 2027. We believe cash flow from operations and availability under the Revolving Credit Facility will be sufficient to cover these estimated future development costs.

The following table sets forth production, price and cost data for the years ended December 31, 2022, 2021, and 2020.

The following table sets forth information regarding our PDP wells as of December 31, 2022:

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2022.

The following table sets forth the number of total net undeveloped acres as of December 31, 2022 that will expire in 2023, 2024, 2025 and 2026 unless production is established within the spacing units covering the acreage prior to the expiration dates or unless such leasehold rights are extended or renewed.

The leases comprising the acreage that is subject to expiration as set forth in the table above will generally expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which case the lease will remain in effect until the cessation of production. Upon expiration of the primary term, we will lose our interests in the associated acreage unless fully held by production, maintained through our delivery of a lease extension payment or, in the case of many of our leases, we utilize the “continuous development clause” that permits us to continue to hold such acreage if we initiate additional development activities within 120-180 days after the completion of the last well drilled on such lease. Thereafter, the lease remains held under the continuous development clause so long as we undertake additional development activities every 120 to 180 days or until the entire lease is held by production. There can be no assurances as to our ability to maintain such acreage. For more information, see "Item 1A. Risk Factors" appearing elsewhere in this Annual Report.

The table below sets forth the results of our operated drilling activities for the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or

are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Dry wells are those that prove to be incapable of producing hydrocarbons in sufficient quantities to justify completion.

As of December 31, 2022, we were not a party to any long-term drilling rig contracts. The following table provides our wells in progress, as well as the various stages of such progress, at December 31, 2022.

We are party to various long-term agreements that require us to physically deliver crude oil and natural gas. These delivery commitments require us to deliver 4.4 MMBoe in 2023 and 7.0 MMBoe thereafter. These commitments are contracted marketing and gathering arrangements that require delivery of a fixed and determinable quantity of crude oil, natural gas, or NGLs in the future. We believe that our current production and reserves are sufficient to satisfy the majority of these commitments and alternatively we could purchase sufficient volumes of oil, natural gas and NGL in the market at prevailing index-related prices to satisfy the commitments, if needed. We incurred shortfalls related to some of our gathering and transportation commitments and as a result paid $4.5 million, $5.8 million and $14.5 million (including the termination of a midstream contract) for the years ended December 31, 2022, 2021 and 2020, respectively.

Production from our oil and natural gas properties is marketed using methods that are consistent with industry practices. Sales prices for oil and natural gas production, including natural gas with recoverable NGLs, are negotiated based on factors normally considered in the industry, such as an index or spot price, price regulations, distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions. In areas where there is no practical or commercial access to pipelines, oil is transported to storage facilities by truck. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted.

During the years ended December 31, 2022, 2021 and 2020, we sold oil and natural gas production representing 10% or more of total revenues to the following purchasers:

While the loss of a significant purchaser could result in a temporary interruption in sales of, or a lower price for, our production, we believe that the loss of any such purchasers would not have a material adverse effect on our operations because there are other purchasers in our producing regions.

We have entered into certain oil and natural gas transportation and gathering agreements with various pipeline carriers. Under these agreements, we are obligated to ship minimum daily quantities or pay for any deficiencies at a specified rate. We are also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity that we utilize. If we do not utilize the capacity, we can release it to others, thus reducing our potential liability.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil or natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in evaluating and bidding for oil and natural gas properties.

There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of developing oil or natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.

Generally, demand for oil, natural gas and NGL decreases during the spring and fall months and increases during the summer and winter months. However, certain natural gas and NGL markets utilize storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. In addition, seasonal anomalies such as mild winters or mild summers can have a significant impact on prices. These seasonal anomalies can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages, increased costs or delay operations.

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.

Prior to completing an acquisition of producing leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this Annual Report.

We manage our operations through (i) management and corporate-level services provided by the Manager and (ii) asset-level services and operations provided by our approximately 870 employees that dedicate all or substantially all of their time to our business. We hire independent contractors on an as-needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.

Our executive leadership team meets regularly with each subsidiary to provide guidance and resources, empowering operational leaders to create value and improve EHS performance. Workplace safety procedures and programs include but not limited to confined space entry, emergency response, fall protection, hearing conservation, hot work, hydrogen sulfide, incident reporting and investigation, personal protective equipment and spill prevention. Safety performance is tracked on a monthly basis across operations and trends guide safety program improvements.

Our oil, natural gas and NGL exploration, development, production, gathering, transportation, sales and related operations and activities are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with such rules and regulations can result in administrative, civil or criminal penalties, compulsory remediation and imposition of natural resource damages or other liabilities. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such requirements. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, we believe these obligations generally do not impact us differently or to any greater or lesser extent than they affect other operators in the oil and natural gas industry with similar operations and types, quantities and locations of production.

In many states oil and natural gas companies are generally required to obtain permits for drilling operations, provide drilling bonds, file reports concerning operations and meet other requirements related to the exploration, development and production of oil, natural gas and NGL. Such states also have statutes and regulations addressing conservation matters, including provisions for unitization or pooling of oil and natural gas interests, rights and properties, the surface use and restoration of properties upon which wells are drilled and disposal of water produced or used in the D&C process. These regulations include the establishment of maximum rates of production from oil and natural gas wells, rules as to the spacing, plugging and abandoning of such wells, restrictions on venting or flaring oil and natural gas and requirements regarding the ratability of production, as well as rules governing the surface use and restoration of properties upon which wells are drilled.

These laws and regulations may limit the amount of oil, natural gas and NGL that can be produced from wells in which we own an interest and may limit the number of wells, the locations in which wells can be drilled or the method of drilling wells. Additionally, the procedures that must be followed under these laws and regulations may result in delays in obtaining permits and approvals necessary for our operations and therefore our expected timing of drilling, completion and production may be negatively impacted. These regulations apply to us directly as the operator of our leasehold. The failure to comply with these rules and regulations can result in substantial penalties.

Sales of condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, the U.S. Congress could reenact price controls in the future.

Our sales of NGLs are affected by the availability, terms and cost of transportation. The transportation of NGLs in common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate oil, NGL and other liquid pipeline transportation rates under the ICA. In general, interstate liquids pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances.

Intrastate liquids pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of liquids transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Historically, the transportation and sale for resale of oil and natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, the U.S. Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA, and culminated in adoption of the Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the NGA, and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances,

intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by the U.S. Congress and by FERC regulations.

The EP Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC. The EP Act of 2005 also provided FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increased FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. In January 2023, the maximum penalty increased to $1,496,035 per violation per day to account for inflation. The civil penalty provisions are applicable to entities that engage in the sale and transportation of natural gas for resale in interstate commerce.

On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (ii) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) to engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

On December 26, 2007, FERC issued Order No. 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas producers, gatherers and marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

Gathering service, which occurs upstream of jurisdictional transportation services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transportation function, FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transportation facilities as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transportation services and federally unregulated gathering services could be the subject of ongoing litigation, so the classification and regulation of our gathering facilities could be subject to change based on future determinations by FERC, the courts or the U.S. Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Contango Resources, LLC has an interstate liquids pipeline that is considered a common carrier pipeline subject to regulation by FERC under the ICA. Unless we obtain a waiver of the applicable provisions, the ICA requires that we maintain tariffs on file with FERC for interstate movements of liquids on our pipelines. Those tariffs set forth the rates we charge for providing transportation services as well as the rules and regulations governing these services. The ICA requires that tariff rates for liquids pipelines, which include both crude oil pipelines and refined products pipelines, be just and reasonable and non-discriminatory. Many FERC-regulated liquids pipelines, including Contango Resources, LLC, use the FERC indexing methodology to change its rates. FERC, however, retained cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach that may be used in certain specified circumstances. For those pipelines that use the FERC indexing methodology, FERC reviews the index formula every five years to determine whether a change in the methodology is required or, if not, to determine the appropriate index for the subsequent five-year period. On January 20, 2022, FERC issued an order on rehearing of its December 17, 2020 Order Establishing Index Level in which the FERC reduced the oil pricing index factor

for oil pipelines to use for the current five-year period. As a result, the ceiling levels computed for July 1, 2021 to June 30, 2022, as well as the ceiling levels for the period July 1, 2022, to June 30, 2023, and the resulting rates currently in effect for our pipelines, were recomputed to account for the appropriate index factor. FERC denied rehearing of the January 20 order on May 6, 2022. Certain parties have now appealed the January 20 and May 6 FERC orders, and the appeals remain pending before the DC Circuit.

From time to time we might enter into arrangements to transport liquids on an affiliated ICA-jurisdictional pipeline, and FERC may more heavily scrutinize agreements between ICA jurisdictional pipelines and their affiliates. On December 15, 2022, FERC issued a Proposed Policy Statement on Oil Pipeline Affiliate Committed Service seeking comments on a new framework for FERC to analyze agreements between an ICA-jurisdictional pipeline and an affiliated shipper. Under the Proposed Policy Statement, if following an open season the only shipper agreeing to the noticed service is an affiliate of the pipeline, then FERC would presume the contract is unduly discriminatory and not just and reasonable and require the affiliates to rebut that presumption with additional evidence supporting the justness and reasonableness of the agreement. Comments on the Proposed Policy Statement are due in the spring of 2023. Notices of proposed policy statements are not final rules and FERC’s determination regarding changes to current practices are not required to be completed within a specific timeframe or at all. Additionally, on December 16, 2022, FERC issued an order in FERC Docket No. OR17-2-001 that clarified FERC’s rules and practices enforcing the ICA’s prohibition on certain transactions on ICA jurisdictional pipelines and affiliated shippers. Under FERC’s recent clarification of the ICA, FERC also will scrutinize transactions between jurisdictional pipelines and affiliated shippers to ensure a common parent company is not subsidizing transportation service on the pipeline. FERC’s treatment of contracts between affiliates on ICA jurisdictional pipelines has been changing in recent years, and it is difficult to predict the level and type of scrutiny that will be applied in the future and the extent to which affiliate contracts may be limited.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical and financial sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and under the Commodity Exchange Act (“CEA”), and regulations promulgated thereunder enforced by the CFTC. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity as well as certain disruptive trading practices. The CFTC also has statutory authority to seek civil penalties of up to the greater of approximately $1,404,520 (adjusted annually for inflation) or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Further, the FTC has the authority under the Federal Trade Commission Act (“FTCA”) and the Energy Independence and Security Act of 2007 (“EISA”) to regulate wholesale petroleum markets. The FTC has adopted anti-market manipulation rules, including prohibiting fraud and deceit in connection with the purchase or sale of certain petroleum products, and prohibiting omissions of material information which distort or are likely to distort market conditions for such products. In addition to other enforcement powers it has under the FTCA, the FTC can sue violators under EISA and request that a court impose fines of approximately $1,426,319 (adjusted annually for inflation) per violation per day.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. As such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Changes in law and to FERC or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers and marketers with which we compete.

Our operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing environmental protection, occupational safety and health, and the release, discharge or disposal of materials into the environment, some of which carry substantial administrative, civil and criminal penalties for failure to comply. Applicable U.S. federal environmental laws include, but are not limited to, RCRA, CERCLA, OPA, the CWA, the CAA, the SDWA, the ESA, and the MBTA. In addition, state and local laws and regulations set forth specific standards for drilling wells, the maintenance of bonding requirements in order to drill or operate wells, the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, the prevention and cleanup of pollutants, and other matters. These laws and regulations may, among other things, require the acquisition of permits to conduct exploration, drilling, and production operations; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the D&C process; limit or prohibit construction or drilling activities in sensitive areas such as wilderness, wetlands, critical habitat of protected species, frontier and other protected areas; require investigatory or remedial actions to prevent or mitigate pollution conditions caused by our operations; impose obligations to reclaim and abandon well sites and pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. Additionally, the U.S. Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs. Although environmental obligations have not historically had a material adverse impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties, loss of permits or leases, the imposition of investigatory or remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas. These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. It is possible that, over time, environmental regulation could evolve to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or reinterpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities or waste handling, storage, transport, disposal, or remediation requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our results of operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot be sure that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Although we believe that we are in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our business, there can be no assurance that this will continue in the future.

The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on its capital expenditures, results of operations or financial position.

CERCLA, also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release of a “hazardous substance” into the environment. These classes of persons, or, as termed in CERCLA, potentially responsible parties, include the current and past owners or operators of a disposal site or site where the release occurred and anyone who disposed or arranged for the disposal of the hazardous substances found at such sites. Under CERCLA, such persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances under CERCLA and other environmental laws but we are unaware of any liabilities for which we may be held responsible that would materially and adversely affect our business operations. While petroleum and crude oil fractions are

generally not considered hazardous substances under CERCLA and its analogues because of the so-called “petroleum exclusion,” adulterated petroleum products containing other hazardous substances have been treated as hazardous substances in the past.

We also generate solid and hazardous wastes that may be subject to the requirements of the RCRA, and analogous state laws. RCRA regulates the generation, handling, storage, treatment, transport and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes “drilling fluids, produced waters and other wastes associated with the development or production of oil, natural gas or geothermal energy” from regulation as hazardous wastes. With the approval of the EPA, individual states can administer some or all of the provisions of RCRA and some states have adopted their own, more stringent requirements. However, legislation has been proposed from time to time and various environmental groups have filed lawsuits that, if successful, could result in the reclassification of certain oil and natural gas exploration and production wastes as “hazardous wastes,” which would make such wastes subject to much more stringent handling, disposal and clean-up requirements. Any future loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes are determined to have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

We currently own, lease or operate numerous properties that may have been used by prior owners or operators for oil and natural gas development and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations where such substances have been taken for recycling or disposal. In addition, some of our properties may have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and/or analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including spills and leaks of oil and other natural gas wastes, into or near waters of the United States or state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The discharge of dredge and fill material into regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). The scope of these regulated waters has been subject to controversy in recent years. In September 2015, the EPA and the Corps issued new rules revising the definition of “waters of the United States” (the “Clean Water Rule”), but in April 2020, the EPA and the Corps replaced the Clean Water Rule with the NWPR, which narrows the definition of “waters of the United States” to four categories of jurisdictional waters and includes 12 categories of exclusions, including groundwater. However, district courts for the U.S. Districts of Arizona and New Mexico have vacated the NWPR, and the Biden Administration has announced its intention to develop its own definition for “waters of the United States. In January 2023, the agencies published a final rule defining “waters of the United States” according to the broader pre-2015 standards, with updates to incorporate existing Supreme Court decisions and agency guidance. Additionally, the Supreme Court of the United States heard arguments on a case regarding the scope of “waters of the United States” in October 2022, a decision on which is expected in 2023, which could impact the regulatory definition or its implementation. To the extent any judicial ruling or administrative rulemaking expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits, including for dredge and fill activities in wetland areas.

The process for obtaining permits also has the potential to delay our operations. Additionally, spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” are required by federal law in connection with on-site storage of significant quantities of oil. Compliance may require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak.

The SDWA grants the EPA broad authority to take action to protect public health when an underground source of drinking water is threatened with pollution that presents an imminent and substantial endangerment to humans. The SDWA also regulates saltwater disposal wells under the UIC program. The EP Act of 2005 amended the UIC provisions of the SDWA to expressly exclude certain hydraulic fracturing from the definition of “underground injection,” but disposal of hydraulic fracturing fluids and produced water or their injection for enhanced oil recovery is not excluded. In 2014, the EPA issued permitting guidance governing hydraulic fracturing with diesel fuels. While we do not currently use diesel fuels in our hydraulic fracturing fluids, we may become subject to federal permitting under SDWA if our fracturing formula changes. Additionally, we may incur significant costs to comply with disposal requirements for hydraulic fracturing fluids and produced water. For more information, see "Item 1A. Risk Factors."

The CAA and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and other requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the NAAQS for ozone from 75 to 70 parts per billion and completed attainment/non-attainment designations in 2018. In December 2020, the EPA announced its intention to leave the ozone NAAQS unchanged at 70 parts per billion; however, this decision has been subject to legal challenges, and the Biden Administration has formally announced that it would reconsider the 2020 decision. To the extent more stringent standards are implemented, we could be required to incur further costs for pollution control equipment or other compliance measures. Further, in June 2016, the EPA also finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. These rules could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements.

State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, the EPA has adopted new rules under the CAA that require the reduction of volatile organic compound (“VOC”) and methane emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. In addition, the regulations place new requirements to detect and repair VOC and methane at certain well sites and compressor stations. However, in September 2020, the EPA finalized a rule removing transmission and storage activities from the purview of the rules, thereby rescinding the VOC and methane emissions limits applicable to such activities and rescinding the methane specific limits for other activities but maintaining emissions limits for VOCs. However, subsequently, the U.S. Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act to repeal the September 2020 rulemaking, effectively reinstating the prior standards. Additionally, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOOb as new source and OOOOc as first-time existing source standards of performance for methane and VOC emissions for the crude oil and natural gas source category. Owners or operators of affected emission units or processes would have to comply with specific standards of performance that may include leak detecting using optical gas imaging and subsequent repair requirements, reduction of regulated emissions through capture and control systems, zero-emission requirements for certain equipment or processes, operations and maintenance requirements and requirements for “green well” completions. In November 2022, the EPA published a supplemental methane proposal, which, among other items, sets forth specific revisions strengthening the first nationwide emission guidelines for states to limit methane emissions from existing crude oil and natural gas facilities. The proposal also revises requirements for fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys, establishes a “super-emitter” response program to timely mitigate emissions events as detected by governmental agencies or qualified third parties, and provides additional options for the use of advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions. The proposal is currently subject to public comment and is expected to be finalized in 2023; however, it is likely that these requirements will be subject to legal challenges. Separately, in August 2022, the IRA 2022 was signed into law, which amends the CAA to establish the first ever federal fee on methane emissions from sources required to report their GHG emissions to the EPA, including certain oil and gas operations. The methane emissions charge will start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and subsequent years. Calculation of the methane fee is based on certain thresholds

established in the IRA 2022. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of natural gas projects and increase our costs of development, which costs could be significant.

Climate change continues to attract considerable public and scientific attention. As a result, our operations as well as the operations of our operators are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHG. At the federal level, no comprehensive climate change law or regulation has been implemented to date, though recently passed laws such as the IRA 2022 advance numerous climate-related objectives. For example, the IRA 2022, in addition to the methane fee discussed above, appropriates significant federal funding for renewable energy initiatives. The EPA has also adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, and together with DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. The federal regulation of methane emissions from oil and gas facilities has been subject to controversy in recent years. For more information, see “Part I., Items 1 and 2. Business and Properties—Legislative and regulatory environment—Air emissions.”

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of GHG emissions. For example, California, through CARB has implemented a cap and trade program for GHG emissions that sets a statewide maximum limit on covered GHG emissions, and this cap declines annually to reach 40% below 1990 levels by 2030. Covered entities must either reduce their GHG emissions or purchase allowances to account for such emissions. Separately, California has implemented LCFS and associated tradable credits that require a progressively lower carbon intensity of the state’s fuel supply than baseline gasoline and diesel fuels. Such programs work alongside increased regulation by California seeking to reduce both the supply and demand for fossil fuels in the state, to include, for example, the phasing out of the sale of vehicles with internal combustion engines. CARB has also promulgated regulations regarding monitoring, leak detection, repair and reporting of methane emissions from both existing and new oil and gas production facilities. Similar regulations applicable to oil and gas facilities have been promulgated in Colorado.

restrictive GHG emission limitations for oil and gas facilities. Litigation risks are also increasing, as a number of parties have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed climate change or alleging that companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.

There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. 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. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. President Biden signed an executive order calling for the development of a “climate finance plan” and, separately, in late 2020, the Federal Reserve announced that it had joined the NGFS, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. In September 2022, the Federal Reserve announced that six of the U.S.’ largest banks would participate in a pilot climate scenario analysis to enhance the ability of firms and supervisors to measure and manage climate-related risk. Released in January 2023, the pilot exercise is designed to analyze the impact of both physical and transition risks related to climate change on specific assets of the banks’ portfolios. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. Additionally, the SEC has proposed rules requiring climate disclosures from registrants, including data on Scope 1 and 2 GHG emissions and, in some cases, Scope 3, as well as a registrant’s climate-related business strategy. A final rule is expected to be released in the second quarter of 2023. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from oil and natural gas producers, such as ourselves or our operators, or otherwise restrict the areas in which we may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for or erode value for, the oil and natural gas that we produce. Additionally, political, litigation, and financial risks may result in our restricting or canceling oil and natural gas production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing our ability to continue to operate in an economic manner. Moreover, climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events (including storms, wildfires, and other natural disasters) or changes in meteorological and hydrological patterns, that could adversely impact our operations, as well as those of our operators and their supply chains. Such physical risks may result in damage to our facilities or otherwise adversely impact our operations, such as if we become subject to water use curtailments in response to drought, or demand for our products, such as to the extent warmer winters reduce the demand for energy for heating purposes. Such physical risks may also impact our supply chain or infrastructure on which we rely to produce or transport our products. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

Hydraulic fracturing is a common practice that is used to stimulate production of oil and/or natural gas from low permeability subsurface rock formations and is important to our business. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the hydrocarbon-bearing rock formation and stimulate production of hydrocarbons. We regularly use hydraulic fracturing as part of our operations. Presently, hydraulic fracturing is primarily regulated at the state level, typically by state oil and natural gas commissions, but the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. For example, the EPA finalized rules under the CWA in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

In addition, there have been heightened concerns by the public about hydraulic fracturing causing damage to aquifers and there is potential for future regulation to address those concerns. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that certain activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. Additionally, BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. While this rule was subsequently rescinded in December 2017, which rescission was upheld by the District Court

of Northern California, the Biden Administration may seek to revisit these regulations. For example, the EPA finalized rules under the CWA in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

Separately, the Biden Administration may also pursue further restriction of hydraulic fracturing and other oil and gas development on federal lands. For example, on January 27, 2021, President Biden issued an executive order that suspended the issuance of new leases for oil and gas development on public lands, but not on existing operations under valid leases or on tribal lands that the federal government merely holds in trust, pending completion of a comprehensive review and reconsideration of the federal oil and natural gas permitting and leasing practices. In response to this, in November 2021, the DOI released a report on the federal oil and gas leasing program that included several recommendations for how to reform the program. IRA 2022 responded to one of the report’s recommendations and increased royalty rates, to include onshore royalty rates to 16 ⅔%. Several of the other recommendations, however, require further Congressional action and include, among other items, revising bidding practices to avoid leasing of low potential lands; and performing more meaningful public and tribal consultations regarding the leasing and permitting processes. Provisions of these reforms have been subject to litigation, and the leasing suspension was ultimately halted by a permanent injunction in August 2022. A portion of our net acreage and total proved reserves are on federal land. Although permit consideration has resumed, we cannot guarantee that further action will not be taken to curtail oil and gas development on federal lands. To the extent we are unable to obtain the leases, permits, or other authorizations required for our operations or business strategy, our business performance and results of operations may be adversely affected.

Separately, in March 2016, the U.S. Occupational Safety and Health Administration issued a final rule to impose stricter standards for worker exposure to silica, which went into effect on June 23, 2021 for hydraulic fracturing employers. We may be required to incur additional costs associated with compliance with these standards.

At the state level, several states, including Texas, have adopted or are considering legal requirements that require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements. For example, Colorado has adopted more stringent setbacks for oil and gas development. In California, Senate Bill No. 1137 was signed into law on September 16, 2022, which establishes 3,200 feet as the minimum distance between new oil and gas production wells and certain sensitive receptors such as homes, schools or parks effective January 1, 2023. However, on February 3, 2023, the Secretary of State of California certified a requisite number of signatures collected by proponents of a voter referendum, thereby qualifying the Bill for the November 2024 ballot. Accordingly, Senate Bill No. 1137 is stayed until it is put to a vote. Local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. For example, in January 2023, the Board of Supervisors of Los Angeles County in California adopted an ordinance prohibiting new oil wells and production facilities in all zones, designating existing oil wells and production facilities as nonconforming uses in all zones and establishing regulations for existing oil wells and production facilities, to include the phasing out of existing operations. Moreover, existing oil and gas facilities within the setback zone in Los Angeles County will be impacted if Senate Bill No. 1137 is voted into law in November 2024. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and attendant permitting delays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential legislation or regulation governing hydraulic fracturing, and any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.

The OPA establishes strict liability for owners and operators of facilities that are the source of a release of oil into waters of the U.S. The OPA and its associated regulations impose a variety of requirements on responsible parties, including owners and operators of certain facilities from which oil is released, related to the prevention of oil spills and liability for damages resulting from such spills. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct, resulted from violation of a federal safety, construction or operating

regulation, or if the party fails to report a spill or to cooperate fully in the cleanup. Few defenses exist to the liability imposed by the OPA. The OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.

The ESA restricts activities that may affect endangered or threatened species or their habitat. Similar protections are offered to migratory birds under the MBTA. We may conduct operations on natural gas leases in areas where certain species that are or could be listed as threatened or endangered are known to exist. For example, a 12-month review is currently pending to determine whether the dunes sagebrush lizard should be listed, a decision on which is expected in June 2023, and, in November 2022, the FWS listed two distinct population segments of the lesser prairie-chicken under the ESA. In August 2020, the FWS and the National Marine Fisheries Service issued three rules amending the implementation of the ESA regulations, among other things revising the process for listing species and designating critical habitat. However, in July 2022, FWS and NMFS rescinded two rules related to the definition of “critical habitat,” and the Biden Administration has stated that it is reviewing several other Trump-era ESA rules.

The DOI also issued an opinion in December 2017 that would narrow certain protections afforded to migratory birds pursuant to the MBTA. In August 2020, the U.S. District Court for the Southern District of New York vacated this opinion as contrary to law. While the FWS subsequently finalized a rule incorporating the DOI opinion, the rule was revoked on October 4, 2021, and FWS returned to pre-2017 implementation of the MBTA, including the ability to enforce the MBTA against accidental harm or death to birds (known as “incidental take”). FWS has published an advanced notice of proposed rulemaking to codify a general prohibition on incidental take while also establishing a process to regulate or permit exceptions to such a prohibition. A notice of proposed rulemaking is scheduled for release toward the end of the first quarter of 2023. . The identification or designation of previously unprotected species, such as the dunes sagebrush lizard, lesser prairie chicken, and greater sage grouse, as threatened or endangered, or the redesignation of a species from threatened to endangered, in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other

operations. In particular, certain areas within California have been subject to significant permitting uncertainty in the past several years, resulting in the delay of receipt of drilling permits.

We are subject to a number of federal and state laws and regulations, including the federal OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers. For example, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we maintain, organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.

We maintain insurance against some contamination risks associated with our development activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a material and adverse effect on our financial condition and operations. Further, we have no coverage for gradual, long-term pollution events.

Our revenues, operating results, profitability, liquidity and ability to grow depend primarily upon the prices we receive for the oil, natural gas and NGL we sell. We require substantial expenditures to replace our oil, natural gas and NGL reserves, sustain production and fund our business plans, including our development plan. Low oil, natural gas and NGL prices resulting from reduced demand caused by the conflict in Ukraine, accelerated substitution of renewable forms of energy for oil and gas, the continued impact of the COVID-19 pandemic, actions of OPEC and other factors materially affected our revenues, particularly before the effects of commodity derivatives, operating results and cash flows in 2022. While oil, natural gas and NGL prices have returned to pre-pandemic levels, the continued impact of the COVID-19 pandemic and the associated global oil, natural gas and NGL demand may negatively affect the amount of cash available for capital expenditures and debt repayment, our ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on our business, prospects, financial condition, results of operations and cash flows. In addition, low prices may reduce the quantities of oil, natural gas and NGL reserves that may be economically produced and result in an impairment of our oil and natural gas properties.

Historically, the markets for oil, natural gas and NGL have been volatile, and they are likely to continue to be volatile. For

example, the conflict between Russia and Ukraine has contributed to significant increases and volatility in the price for oil and natural gas. Wide fluctuations in oil, natural gas and NGL prices may result from relatively minor changes in the supply of or demand for oil, natural gas and NGL market uncertainty and other factors that are beyond our control, including:

Lower commodity prices may reduce our operating margins, cash flow and borrowing ability. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop future reserves or make acquisitions could be adversely affected. Also, using lower prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits. While the ongoing effects of the COVID-19 pandemic on our operations have decreased lately, any continuing or worsening impact of the COVID-19 pandemic may adversely affect our drilling economics, cash flow and our ability to raise capital, which may require us to re-evaluate and postpone or substantially restrict our development program, and result in the reduction of some of our PUD reserves and related PV-0 and PV-10. As a result, a substantial or extended decline in commodity prices, such as what occurred in early 2020, may materially and adversely affect our future business, financial

condition, results of operations, liquidity and ability to meet our financial commitments or cause us to delay our planned capital expenditures.

We intend to pursue a strategy focused on both reinvestment and future acquisitions, which is designed to obtain the optimal risk adjusted returns through commodity cycles. Accordingly, in the future we may make acquisitions of businesses, assets or properties that we expect to complement or expand our current assets. For example, Crescent Energy Company was created through the Merger Transactions and in March 2022, we acquired certain exploration and production assets in the state of Utah pursuant to the Uinta Transaction (as defined herein). However, we may not be able to identify attractive acquisition opportunities in the future. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets.

The success of any completed acquisition, including the Uinta Transaction, will depend on our ability to integrate effectively the acquired business, asset or property into our existing operations. The process of integrating acquired businesses, assets and properties may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. For example, as with other operators in the area, certain potential midstream constraints may create operational challenges for us in the Uinta Basin. The integration of acquisitions is a complex, costly and time-consuming process, and our management may face significant challenges in such process. Some of the factors affecting integration will be outside of our control, and any one of them could result in increased costs and diversion of management’s time and energy, as well as decreases in the amount of expected revenue.

Our failure to achieve consolidation savings, to incorporate the acquired businesses, assets and properties into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material and adverse effect on our financial condition and results of operations.

Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves. Our estimates of our SEC reserves are based upon average commodity prices over the prior 12 months, which may not reflect actual prices received for our production. For example, our reserve volumes and PV-10 as disclosed in this Annual Report are based on assumed commodity prices of $93.67 per Bbl of oil and $6.36 per MMBtu of natural gas as of December 31, 2022, which are substantially higher than the five year NYMEX forward curve range of $62.76 to $80.50 per Bbl of oil and $3.80 to $5.30 per Mcf of natural gas. Accordingly, you are cautioned not to place undue weight on our reserve volumes or PV-10 based on such pricing when evaluating our financial condition or an investment in our securities. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir. The reports rely upon various assumptions, including assumptions regarding future oil and natural gas prices, our drilling program, production levels, and operating and development costs. In addition, the reserves that we present herein are aggregated from several reports, which were prepared by several engineering firms and therefore may be based on slightly different assumptions and preparation and review procedures. Our ability to develop any identified drilling location is subject to various limitations and any drilling activities we are able to conduct may not be successful. As a result, our actual drilling activities may materially differ from those presently identified and could result in downward revisions of estimated proved reserves. In addition, loss of production and leasehold rights due to mechanical failure or depletion of wells and our inability to re-establish their production may occur in certain cases. Production from wellbores may be affected by nearby fracturing activities by offset operators or us, resulting in reserve revisions.

As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling and production. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. Sustained lower prices will cause the 12-month weighted average price to decrease over time as the lower

prices are reflected in the average price, which may result in the estimated quantities and present values of our reserves being reduced.

Any material inaccuracies in our reserves estimates could also materially affect our borrowing base and liquidity under the Revolving Credit Facility. If the borrowing base under the Revolving Credit Facility decreases as a result of any reductions in our reserve estimates, we may have limited ability to obtain the capital necessary to sustain our operations at current and anticipated future levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all.

You should not assume that the present value of future net revenues from our proved reserves, as reflected in our Standardized Measure, PV-0 value and PV-10 value, is the current market value of our estimated oil and natural gas reserves. We currently base the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding 12 months. For example, our reserve volumes, PV-0 and PV-10 as disclosed in this Annual Report are based on assumed commodity prices of $93.67 per Bbl of oil and $6.36 per MMBtu of natural gas as of December 31, 2022, which are substantially higher than five year NYMEX forward curve range of $62.76 to $80.50 per Bbl of oil and $3.80 to $5.30 per Mcf of natural gas. Accordingly, you are cautioned not to place undue weight on our reserve volumes, PV-0 or PV-10 based on such pricing when evaluating our financial condition or an investment in our securities. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:

The timing of both our production and our incurrence of expenses in connection with the development and production of, and investment in, our oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues at PV-10 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimates.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on each reservoir’s characteristics. Except to the extent that we conduct successful exploration, exploitation, development or reinvestment activities or acquire properties containing proved reserves, our proved reserves will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves as well as the pace of D&C of new wells. Additionally, the business of exploring for, exploiting, developing or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited, unavailable or on terms deemed unacceptable by us, our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves or to return capital to our investors would be impaired.

As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques as well as enhanced recovery operations. The utilization of these techniques requires substantially greater capital expenditures as compared to the completion cost of a vertical well or a horizontal well utilizing less advanced techniques and therefore may result in fewer wells being completed or

We utilize third-party services to maximize the efficiency of our operation. The cost of oilfield services typically fluctuates based on demand for those services, and the increase in commodity prices and supply constraints due to the conflict in Ukraine, the COVID-19 pandemic, rising interest rates and associated policies of the Federal Reserve or otherwise has increased the cost of oilfield services. While we currently have excellent relationships with oilfield service companies, there is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of equipment, supplies or personnel could delay or adversely affect our development and exploitation operations, which could have a material and adverse effect on our business, financial condition or results of operations.

The U.S. inflation rate has been steadily increasing since 2021 and into 2023. These inflationary pressures have resulted in and may result in additional increases to the costs of our oilfield goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates multiple times in 2022 and the U.S. Federal Reserve has indicated its intention to continue to raise benchmark interest rates throughout the remainder of 2023 in an effort to curb inflationary pressure on the costs of goods and services across the U.S., which could have the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—could hurt the financial and operating results of our business. To the extent elevated inflation remains, we may experience further cost increases for our operations, including oilfield services, labor costs and equipment if our drilling activity increases.

Higher oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to recover higher costs through higher oil and natural gas prices and revenues, would negatively impact our business, financial condition and results of operations.

The oil and natural gas industry is capital intensive. We have made and expect to continue to make substantial capital expenditures in our business for the development of, and reinvestment in, oil and natural gas reserves. We have historically funded development and operating activities primarily through the sale of our oil, natural gas and NGL production. If necessary, we may also access capital through proceeds from asset dispositions, borrowings under the Revolving Credit Facility and capital markets offerings from time to time. Our cash flow from operations and access to capital are subject to a number of variables, including:

If our revenues or the borrowing base under the Revolving Credit Facility decrease as a result of lower commodity prices, operating difficulties, production cost increases, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to conduct our operations at expected levels. The Revolving Credit Facility and the documents

governing our other indebtedness may restrict our ability to obtain new debt financing. If additional capital is required, we may not be able to obtain debt and/or equity financing on terms favorable to us, or at all due to rising interest rates and associated policies of the Federal Reserve or otherwise, which could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our reserves, production and cash flows, and could adversely affect our business, results of operation, financial conditions and ability to make payments on our outstanding indebtedness.

Recovery of PUDs requires significant capital expenditures and successful drilling operations. At December 31, 2022 approximately 112.7 MMBoe of our total estimated proved reserves were undeveloped. The reserve data included in our reserve reports assumes that substantial capital expenditures will be made to develop non-producing reserves. The calculation of our estimated net proved reserves as of December 31, 2022 assumes that we will spend $1.7 billion to develop our estimated PUDs. Although cost and reserve estimates attributable to our oil and natural gas reserves have been prepared in accordance with industry standards, we cannot be sure that the estimated costs are accurate. We may need to raise additional capital in order to develop our estimated PUDs, and we cannot be certain that additional financing will be available to us on acceptable terms, if at all. Additionally, extended declines in commodity prices will reduce the future net revenues of our estimated PUDs and may result in some projects becoming uneconomical. Further, our drilling efforts may be delayed or unsuccessful and actual reserves may prove to be less than current reserve estimates, which could have a material and adverse effect on our financial condition, results of operations and future cash flows.

As of December 31, 2022, we have undrilled locations, including both PUD drilling locations and unproved drilling locations. These drilling locations represent a meaningful part of our future development strategy. Our ability to drill and develop these drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system, marketing and transportation constraints, regulatory approvals, labor, takeaway capacity and other factors. Because of these uncertain factors, we do not know if the drilling locations will ever be developed or if we will be able to produce oil or natural gas from these drilling locations at anticipated levels or at all. In addition, unless production is established within the spacing units covering the undeveloped acreage on which some of the locations are located, the leases for such acreage will expire. Therefore, our actual development activities may materially differ from those presently contemplated.

Drilling oil and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive oil and natural gas reserves (including “dry holes”). We must incur significant expenditures to drill and complete wells, the costs of which are often uncertain. It is possible that we will make substantial expenditures on drilling and not discover reserves in commercially viable quantities.

Specifically, we often are uncertain as to the future cost or timing of drilling, completing and operating wells, and our drilling operations and those of our third-party operators may be curtailed, delayed or canceled. The cost of our drilling, completion and well operations may increase and/or our results of operations and cash flows from such operations may be impacted, as a result of a variety of factors, including:

Our failure to recover our investment in wells, increases in the costs of our drilling operations or those of our third-party operators, and/or curtailments, delays or cancellations of our drilling operations or those of our third-party operators in each case due to any of the above factors or other factors, may materially and adversely affect our business, financial condition and results of operations.

Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:

We may also be unable to make attractive acquisitions or asset exchanges, which could inhibit our ability to grow, or could experience difficulty integrating any acquired assets and operations. It may be difficult to identify attractive acquisition opportunities and, even if such opportunities are identified, our debt agreements (including the indentures that govern the 2026 Notes (as defined herein) and the 2028 Notes (as defined herein) contain limitations on our ability to enter into certain transactions, which could limit our future growth.

In addition, other conflicts of interest may arise from time to time in connection with the investment and other activities of us and other members of the KKR Group. With respect to conflicts involving investment opportunities, the Manager will endeavor to resolve any such conflicts of interest in a fair and equitable manner in accordance with the investment allocation policy described above and its prevailing policies and procedures with respect to conflicts resolution among other members of the KKR Group. However, the Manager may have a fiduciary duty to make decisions in the best interests of the Manager's affiliates, including KKR Funds, which may be contrary to our interests. In addition, other conflicts of interest may arise between us, on the one hand, and the Manager or any other member of the KKR Group and their affiliates, including KKR Funds, on the other hand, which may not be resolved in our favor. Further, the Management Agreement provides that nothing shall prevent the Manager from taking certain actions for the sole benefit of the Manager and/or its affiliates. To the fullest extent permitted by law, the Manager and its affiliates, including but not limited to their respective directors, officers, employees, agents, managers, trustees, control persons, partners, stockholders, and equityholders, will not be liable to us or any subsidiary or any of their respective directors, officers, employees, agents, managers, trustees, control persons, partners, stockholders, and equityholders, for any acts or omissions by the Manager or its affiliates, including by their respective directors, officers, employees, agents, managers, trustees, control persons, partners, stockholders, and equityholders, performed in accordance with and pursuant to the Management Agreement, except in cases of bad faith, fraud, willful misconduct or gross negligence. The Management Agreement requires us to reimburse, indemnify and hold harmless the Manager, its affiliates, and their respective directors, officers, employees, managers, trustees, control persons, partners, stockholders, and equityholders, and directors, officers, employees, agents, managers, trustees, control persons, partners, stockholders and equityholders of the foregoing from any and all Losses (as defined in the Management Agreement) arising from any proceeding related to us or acts or omissions of the Manager or its affiliates in connection with the Management Agreement, subject to certain exceptions. However, with the exception of the Manager, no other member of the KKR Group assumes any responsibility to render services to us or to consider our interests and our stakeholders in making any investment or other decisions.

Our certificate of incorporation contains a provision that, to the maximum extent permitted under the law of the State of Delaware, we renounce any interest or expectancy in, or in being offered an opportunity to participate in, business opportunities that are from time to time presented to our officers, directors, the Preferred Stockholder or any partner, manager, member, director, officer, stockholder, employee or agent or affiliate of any such holder. We believe that this provision, which is intended to provide that certain business opportunities are not subject to the “corporate opportunity” doctrine, is appropriate, as the Preferred Stockholder and its affiliates invest in a wide array of companies, including companies with businesses similar to us. As a result of this provision, we may be not be offered certain corporate opportunities which could be beneficial to us and our stockholders.

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, future oil and gas prices and their applicable differentials, development and operating costs, and potential liabilities, including environmental liabilities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review may not reveal all existing or potential problems. In the course of due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with its expectations. For these reasons, the properties we will acquire in connection with any future acquisitions may not produce as expected, which could have a material and adverse effect on our financial condition and results of operations.

The continuing or worsening impact of the COVID-19 pandemic or future outbreaks of disease may materially and adversely affect our business, operating and financial results and liquidity, due to governmental restrictions, associated repercussions and operational challenges to supply and demand for oil and natural gas and the economy generally. The continued impact of the COVID-19 pandemic is uncertain and hard to predict.

While the ongoing effects of the COVID-19 pandemic on our operations have decreased recently. this pandemic has had a material negative impact on our financial results. Although there has been economic recovery and higher oil prices through the year ended December 31, 2022, such negative impact may continue well beyond the containment of the pandemic. While we

have seen oilfield activity improve considerably and global inventories rapidly normalize with continued demand growth

since the low point experienced in 2020, considerable uncertainty remains. An extended period of global supply chain and

economic disruption, as well as significantly decreased demand for oil and gas, due to the COVID-19 pandemic, any future outbreak of diseases or otherwise, could materially affect our business, results of operations, access to sources of liquidity and financial condition.

We follow the successful efforts method of accounting for our oil and gas operations. Under this method, all property acquisition cost and cost of exploratory and development wells are capitalized when incurred, pending determination of whether proved reserves have been discovered. If proved reserves are not discovered with an exploratory well, the cost of drilling the well are expensed. The capitalized costs of our oil and natural gas properties, on a depletion pool basis, cannot exceed the estimated undiscounted future net cash flows of that depletion pool. If net capitalized costs exceed undiscounted future net revenues, we generally must write down the costs of each depletion pool to the estimated fair value (discounted future net cash flows of that depletion pool). Any such charge will not affect our cash flow from operating activities or liquidity, but will reduce our earnings and investors’ equity.

We may also at times record reporting unit goodwill in connection with a business combination. Goodwill has an indefinite useful life but is tested by us for impairment annually, or more frequently if there are changes in future commodity prices, amongst other factors, that may indicate that the fair value of the reporting unit may have been reduced below its carrying value. If the carrying value of the reporting unit exceeds the fair value, we generally must write down goodwill to the estimated

fair value of that reporting unit. Any such charge will not affect our cash flow from operating activities or liquidity but will reduce our earnings and investors’ equity.

A decline in future oil or natural gas prices, or other factors, could cause an impairment write-down of capitalized costs, including goodwill, and a non-cash charge against future earnings. For example, in connection with our annual goodwill impairment test, we recorded impairment charges of $142.9 million, including $77.7 million related to Goodwill and $65.2 million related to Oil and natural gas properties that were determined to not be recoverable, for the year ended December 31, 2022. Further, because of declines in commodity prices, we recorded an impairment charge of $247.2 million to Oil and natural gas properties for the year ended December 31, 2020. Once incurred, a write-down of our assets cannot be reversed at a later date, even if oil or natural gas prices increase.

Our business activities are subject to operational risks, including, but not limited to:

Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension or termination of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

As is customary in the industry, we maintain insurance against some but not all of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material and adverse effect on our business, financial condition and results of operations.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us, particularly following recent consolidation within the industry. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties to consummate transactions in a highly competitive market. Many of our larger competitors not only drill for and produce oil and natural gas, but they also engage in refining operations and market petroleum and other products on a regional, national or worldwide basis. Our competitors may be able to pay more for oil and natural gas properties, and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low oil and natural gas prices, to contract for drilling equipment, to secure trained personnel, and to absorb the burden of present and future federal, state, local and other laws and regulations. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipelines and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. Competition has been strong in hiring experienced personnel, particularly in the engineering and technical, accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive oil and natural gas properties, oil and natural gas companies, and drilling rights. Our inability to compete effectively with our competitors could have a material and adverse impact on our business activities, financial condition and results of operations.

If an examination of the title history of a property reveals that an oil or natural gas lease or other developed rights has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would substantially decline in value. In such cases, the amount paid for such oil or natural gas lease or leases or other developed rights would be lost. It is management’s practice, in acquiring oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be acquired. Rather, we rely upon the judgment of oil and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental or county clerk’s office before attempting to acquire a lease or other developed rights in a specific mineral interest.

Prior to drilling an oil or natural gas well, however, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil or natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the leasehold. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. Such curative work entails expense, and it may happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion. Our failure to obtain perfect title to our leaseholds may adversely impact our ability in the future to increase production and reserves.

Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in which we conduct our business. Such restrictions could affect, among other things, our access to and the permissible uses of our properties as well as the manner in which we produce oil and natural gas and may restrict or prohibit drilling in general. The costs we incur to comply with such restrictions may be significant and our development and production activities may be delayed, curtailed or precluded by such restrictions.

Our operations will involve utilizing some of the latest D&C techniques as developed by us and our service providers. The difficulties we may face drilling horizontal wells include:

The difficulties that we will likely face while completing wells include the following:

Use of new technologies may not prove successful and could result in significant cost overruns or delays or reductions in production, and, in extreme cases, the abandonment of a well. In addition, certain of the new techniques we adopt may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer and emerging formations and areas have limited or no production history and, consequently, we will be more limited in assessing future drilling results in these areas. If its drilling results are less than anticipated, the return on investment for a

particular project may not be as attractive as anticipated, and we could incur material write-downs of unevaluated properties and the value of undeveloped acreage could decline in the future.

The marketability of our production depends in part upon the availability and capacity of oil and natural gas gathering systems, pipelines and other transportation facilities owned by third parties. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities, weather-related operational issues, or due to space being utilized by other companies that have priority transportation agreements. Additionally, new fields may require the construction of gathering systems and other transportation facilities. These facilities may require us to spend significant capital that would otherwise be spent on drilling. The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand.

In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our or our operators’ control, such as pipeline interruptions due to maintenance, excessive pressure, inability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we and our operators are provided with limited notice, if any, as to when these curtailments will arise and the duration of such curtailments. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our acreage, could materially and adversely affect our financial condition, results of operations and cash available for distribution.

We depend upon two significant purchasers for the sale of a substantial portion of our oil and natural gas production, and our contracts with these customers are on a month-to-month basis. For example, for the year ended December 31, 2022, Shell Trading US Company and ConocoPhillips represented approximately 21% and 15%, respectively, of our consolidated revenues. The loss of these customers could materially and adversely affect our revenues and have a material and adverse effect on our financial condition and results of operations.

Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. We do not operate 100% of the total net undrilled locations, and there is no assurance that we will operate all of our other future drilling locations. As a result, we have limited ability to influence or control the operation or future development of certain of these properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties, subject to certain of our election rights. 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. In addition, a third-party operator could also decide to shut-in or curtail production from wells, or plug and abandon marginal wells, on properties in which we own an interest during periods of lower crude oil or natural gas prices. Furthermore, the success and timing of development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:

This limited ability to exercise control over the operations and associated costs of some of our drilling locations could prevent the realization of targeted returns on capital in development or acquisition activities. Further, we may be liable for certain financial obligations of the operator of a well in which we own a working interest to the extent such operator becomes insolvent and cannot satisfy such obligations. Similarly, we may be liable for certain obligations of contractors to the extent such contractor becomes insolvent and cannot satisfy their obligations. The satisfaction of such obligations could have a material and adverse effect on our financial condition. For more information, see "Items 1 and 2. Business and Properties" and "Part II., Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations."

On August 16, 2022, President Biden signed the Inflation Reduction Act of 2022 (“IRA 2022”) into law pursuant to the budget reconciliation process. The IRA 2022 contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. These incentives could further accelerate the transition of the U.S. economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives, which could decrease demand for the oil and gas we produce and consequently materially and adversely affect our business and results of operations. In addition, the IRA 2022 imposes the first ever federal fee on the emission of GHGs through a methane emissions charge. The IRA 2022 amends the federal

CAA to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production and gathering and boosting source categories. The methane emissions charge will start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year thereafter. Calculation of the fee is based on certain thresholds established in the IRA 2022. The methane emissions charge could increase our operating costs and adversely affect our business and results of operations.

The marketing of oil and natural gas production depends in large part on the availability, proximity and capacity of pipelines and storage facilities, gathering systems and other transportation, processing, fractionation, refining and export facilities, as well as the existence of adequate markets. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. Additionally, new fields may require the construction of gathering systems and other transportation facilities. These facilities may require us to spend significant capital that would otherwise be spent on drilling. We rely, and expect to rely in the future, on facilities developed and owned by third parties in order to store, process, transmit and sell our production. Our plans to develop and sell our reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise. If these facilities are unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could materially and adversely affect our ability to produce and market oil and natural gas.

Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The interstate transportation and sale for resale of natural gas are subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by FERC. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. FERC regulates the rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines under the NGA as well as under Section 311 of the NGPA. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, nondiscriminatory basis.

Our sales of oil and NGLs are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and NGLs by pipelines are regulated by FERC under the Interstate Commerce Act. FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and NGL pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to

establish ceilings on interstate oil and NGL pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

As an alternative to pipeline transportation, any transportation of our crude oil and NGLs by rail will also be subject to regulation by the PHMSA and the FRA of the DOT under the Hazardous Materials Regulations at 49 CFR Parts 171-180, including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids.

Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners and other sources for use in our operations. Some areas in which we have operations have experienced drought conditions that could result in restrictions on water use. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas in the affected areas, which could have a material and adverse effect on our financial condition, results of operations and cash flows.

We may be subject to regulation that restricts our ability to discharge water produced as part of our production operations. Productive zones frequently contain water that must be removed in order for the oil and natural gas to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce oil and natural gas in commercial quantities. The produced water must be transported from the leasehold and/or injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability. Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

The disposal of fluids gathered from oil and natural gas producing operations in underground disposal wells has been pointed to by some groups and regulators as a potential cause of increased induced seismic events in certain areas of the country, particularly in Oklahoma, Texas, Colorado, Kansas, New Mexico and Arkansas. Several states have adopted or are considering adopting laws and regulations that may restrict or otherwise prohibit oilfield fluid disposal in certain areas or underground disposal wells, and state agencies implementing those requirements may issue orders directing certain wells in areas where seismic incidents have occurred to restrict or suspend disposal well operations or impose standards related to disposal well construction and monitoring. For example, in September 2021 the TRC issued a notice to operators in the Midland area to reduce daily injection volumes following multiple earthquakes above a 3.5 magnitude over an 18 month period. The notice also

required disposal well operators to provide injection data to TRC staff to further analyze seismicity in the area. Subsequently, the TRC ordered the indefinite suspension of all deep oil and gas produced water injection wells in the area, effective December 31, 2021. The response area has since been expanded to cover an additional 17 wells, following another earthquake in December 2022. Relatedly, in March 2022, the TRC began implementation of its Northern Culberson-Reeves Response Area

Plan to address injection-induced seismicity with the goal to eliminate 3.5 magnitude or greater earthquakes no later than

December 31, 2023. Similarly, in Oklahoma, the Oklahoma Corporation Commission has at times limited drilling or ordered wells to be shut down in response to seismic activity. In November 2021, New Mexico implemented protocols requiring operators to take various actions within a specified proximity of certain seismic activity, including a requirement to limit

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company as defined under that statute. We believe that the Springfield Gathering System, Lost Creek Gathering System, and DJ Basin Erie Hub Gathering System in which we own interests meet the traditional tests FERC has used to establish a pipeline’s status as a gathering pipeline not subject to regulation by FERC. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is fact intensive and the subject of ongoing litigation, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by FERC, the courts or the U.S. Congress. If FERC were to consider the status of the gathering system and determine that it is subject to FERC regulation, the rates for, and terms and conditions of, services provided by that gathering system would be subject to modification by FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs, and adversely affect our business, financial condition, and results of operations.

Our natural gas gathering operations may be subject to certain FERC reporting and posting requirements in a given year. Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transmission services, is regulated by the states onshore and in state waters. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities, and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs. Other FERC regulations may indirectly affect our businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas and liquids regulatory activities, including, for example, its policies on open access transportation, natural gas quality, ratemaking, capacity release and market center promotion, may indirectly affect the intrastate natural gas and liquids markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas and liquids pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to transportation capacity.

We have an interstate liquids pipeline that is considered a common carrier pipeline subject to regulation by FERC under the ICA. Unless we obtain a waiver of the applicable provisions, the ICA requires that we maintain tariffs on file with FERC for interstate movements of liquids on our pipelines. Those tariffs set forth the rates we charge for providing transportation services as well as the rules and regulations governing these services. The ICA requires, among other things, that rates on interstate common carrier pipelines be “just and reasonable” and non-discriminatory. Further, FERC’s scrutiny of transportation service agreements between an ICA jurisdictional pipeline and affiliated shippers or marketers under the just and reasonable and non-discriminatory standard is evolving. The ICA permits interested persons to challenge proposed new or changed rates or rules, and authorizes FERC to investigate such changes and to suspend their effectiveness for a period of up to seven months. Upon completion of such an investigation, FERC may require refunds of amounts collected above what it finds to be a just and reasonable level, together with interest. FERC may also investigate, upon complaint or on its own motion, rates and related rules that are already in effect, and may order a carrier to change them prospectively. Upon an appropriate showing, a shipper may obtain reparations (including interest) for damages sustained for a period of up to two years prior to the filing of its complaint. Changes in FERC’s methodologies for approving rates and the treatment of agreements with affiliated shippers could adversely affect us. Further, challenges to our regulated rates could be filed with FERC and future decisions by FERC regarding our regulated rates and agreements with affiliated shippers could adversely affect our cash flows. We cannot predict the rates we will be allowed to charge in the future for transportation services by such pipelines. For more information, see “Items 1 and 2. Business and Properties—Legislative and regulatory environment.”

The classification of some of our gathering facilities, transportation pipelines, and purchase and sale transactions as FERC-jurisdictional or non-jurisdictional may be subject to change based on future determinations by FERC, the courts or Congress, in which case, our operating costs could increase and we could be subject to enforcement actions under the EP Act of 2005.

In addition, the pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the DOT through PHMSA. PHMSA has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. These standards may be revised by PHMSA over time. For example, in October 2019, PHMSA published three final rules that create or expand reporting, inspection, maintenance, and other pipeline safety obligations. As part of the Consolidated Appropriations Act of 2021, the U.S. Congress reauthorized PHMSA through 2023 and directed the agency to move forward with several regulatory actions, including but not limited to the issuance of final regulations to require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations. A rule to address certain of these requirements was issued in November 2021, which modified pipeline repair criteria, increased monitoring and reporting obligations, and expanded regulatory safety requirements to certain gathering lines in rural areas. An additional rule was finalized in August 2022, which adjusted repair criteria and strengthened integrity management assessment requirements, among other items. PHMSA is continuing to work on developing additional regulations related to safety oversight of gas gathering pipelines, and additional future regulatory action expanding PHMSA’s jurisdiction and imposing stricter integrity management requirements is possible. The adoption of laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operating costs that could be significant. In addition, should we fail to comply with PHMSA or comparable state regulations, we could be subject to substantial fines and penalties. As of March 21, 2022, the maximum civil penalties PHMSA can impose are $239,142 per violation per day, with a maximum of $2,391,412 for a related series of violations.

Under the Domenici-Barton Energy Policy Act of 2005 ("EPAct 2005"), FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1,496,035 per day (adjusted annually for inflation) for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. The EPAct 2005 also authorized FERC to impose civil penalties for violations of the ICA and FERC regulations thereunder, up to a maximum amount that is adjusted annual for inflation, which for 2023 equals $15,662 per day, per violation. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Items 1 and 2. Business and Properties – Legislative and regulatory environment.”

Sales of oil natural gas and NGLs are not currently regulated and are made at negotiated prices. However, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations.

Additionally, FERC, the FTC and the CFTC hold statutory authority to monitor certain segments of the physical and futures energy commodities markets relevant to our business. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil and natural gas, and any hedging activities related to these energy commodities, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. These agencies have substantial enforcement authority, including the ability to impose penalties for current violations of $1,496,035 per day (adjusted annually for inflation) by FERC, $1,404,520 (adjusted annually for inflation) by the CFTC, and $1,426,319 (adjusted annually for inflation) by the FTC, for each violation. The FERC has also imposed requirements related to reporting of natural gas sales volumes that may impact the formation of prices indices. Additional rules and legislation pertaining to these and other matters may be considered or adopted from time to time. Our failure to comply with these or other laws and regulations administered by these agencies could subject us to criminal and civil penalties, as described in "Items 1 and 2. Business and Properties—Legislative and regulatory environment." Failure to comply

with such regulations, as interpreted and enforced, could materially and adversely affect our financial condition or results of operations.

Title VII of Dodd-Frank establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the CFTC and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market. Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized.

In one of its rulemaking proceedings still pending under Dodd-Frank, the CFTC issued on January 30, 2020, a re-proposed rule imposing position limits for certain futures and option contracts in various commodities (including oil and natural gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. A final rule has not yet been issued.

The CFTC has also adopted final rules regarding aggregation of positions, under which a party that controls the trading of, or owns 10% or more of the equity interests in, another party will have to aggregate the positions of the controlled or owned party with its own positions for purposes of determining compliance with position limits unless an exemption applies. The CFTC’s aggregation rules are now in effect, though CFTC staff have granted relief—until August 12, 2025—from various conditions and requirements in the final aggregation rules. With the implementation of the final aggregation rules and upon the adoption and effectiveness of final CFTC position limits rules, our ability to execute our hedging strategies described above could be limited. It is uncertain at this time whether, when and in what form the CFTC’s proposed new position limits rules may become final and effective.

The CFTC issued a final rule on the amount of capital certain swap dealers and major swap participants are required to set aside with respect to their swap business on July 22, 2020. This rule may require our swap dealer counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the costs to us of future financial derivatives transactions.

The CFTC issued a final rule on margin requirements for uncleared swap transactions on January 6, 2016, which includes an exemption from any requirement to post margin to secure uncleared swap transactions entered into by commercial end-users to hedge commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exemption from the otherwise applicable mandatory obligation to clear certain types of swap transactions through a derivatives clearing organization and to trade such swaps on a regulated exchange, which exemption applies to swap transactions entered into by commercial end-users to hedge commercial risks affecting their business. The mandatory clearing requirement currently applies only to certain interest rate swaps and credit default swaps, but the CFTC could act to impose mandatory clearing requirements for other types of swap transactions. Dodd-Frank also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations.

All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. The Volcker Rule provisions of Dodd-Frank may also require our current bank counterparties that engage in financial derivative transactions to spin off some of their derivatives activities to separate entities, which separate entities may not be as creditworthy as the current bank counterparties. Under such rules, other bank counterparties may cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of entities like us, as commercial end-users, to have access to financial derivatives to hedge or mitigate our exposure to commodity price volatility.

As a result, Dodd-Frank and any new regulations issued thereunder could significantly increase the cost of derivative contracts (including through requirements to post cash collateral), which could adversely affect our capital available for other commercial operations purposes, materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts and reduce the availability of derivatives to protect against commercial risks we encounter.

If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and NGL prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and NGL. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of

these consequences could have a material and adverse effect on our consolidated financial condition, results of operations or cash flows.

We may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example, the following federal laws and their state counterparts, as amended from time to time:

These U.S. laws and their implementing regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, discharges to surface water, and disposals or other releases to surface and below-ground soils and ground water. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective actions obligations, the incurrence of capital expenditures, the occurrence of delays in the permitting, development or expansion of projects and the issuance of orders enjoining some or all of our future operations in a particular area. Compliance with more stringent standards and other environmental regulations could restrict our ability to obtain permits for operations or require us to install additional pollution control equipment, the costs of which could be significant. Certain environmental laws and analogous state laws and regulations impose strict joint and several liability, without regard to fault or legality of conduct, for costs required to clean up and restore sites where hazardous substances or other wastes have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, wastes or other materials into the environment. In addition, these laws and regulations may restrict the rate of oil or natural gas production. Historically, our environmental compliance costs have not had a material and adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material and adverse effect on our business and operating results.

Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the oil and natural gas industry could continue,

resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially and adversely affected. See "Items 1 and 2. Business and Properties—Legislative and regulatory environment."

Our oil and natural gas operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or drilling permits could have a material and adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil and natural gas we may produce and sell.

We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of oil and natural gas. The possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our financial condition could be materially and adversely affected.

For example, the TRC has adopted rules and regulations implementing legislation mandating certain clean-up activities for inactive wells and additional requirements related to the approval of plugging extensions. Failure to comply can result in administrative penalties and the loss of an operator’s ability to conduct operations in Texas. A major component of the law is Rule 15, which requires a well operator to comply with certain inactive well clean-up activities, including the disconnection of electricity, purging of all production fluids from inactive lines and tanks and removal of surface equipment for wells that have not produced oil or gas during the preceding year. Noncompliance with Rule 15 could result in administrative penalties of up to $10,000 per violation per day and the loss of an operator’s ability to conduct operations in Texas.

Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. Various proposals and proceedings that might affect the petroleum industry are pending before the U.S. Congress, FERC, various state legislatures and the courts. The industry historically has been heavily regulated and we cannot provide assurance that the less stringent regulatory approach recently pursued by FERC and the U.S. Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices, and passage of incentives or funding for renewable energy projects such as those contained in IRA 2022 could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material and adverse effect on our business, financial condition, results of operations and cash flows.

Climate change continues to attract considerable public and scientific attention. As a result, our operations as well as the operations of our non-operated assets are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHG. At the federal level, no comprehensive climate change law or regulation has been implemented to date, though the IRA 2022 advances numerous climate related objectives. The EPA has, however, adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, and together with DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. The federal regulation of methane emissions from oil and gas facilities has been subject to controversy in recent years. For more information, see "Items 1 and 2. Business and Properties—Legislative and regulatory environment—Air emissions."

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of GHG emissions. For example, California, through CARB, has implemented a cap and trade program for GHG emissions that sets a statewide maximum limit on covered GHG emissions, and this cap declines annually to reach 40% below 1990 levels by 2030. Covered entities must either reduce their GHG emissions or purchase allowances to

account for such emissions. Separately, California has implemented LCFS and associated tradable credits that require a progressively lower carbon intensity of the state’s fuel supply than baseline gasoline and diesel fuels. Such programs work

alongside increased regulation by California seeking to reduce both the supply and demand for fossil fuels in the state, to

include, for example, the phasing out of the sale of vehicles with internal combustion engines. CARB has also promulgated regulations regarding monitoring, leak detection, repair and reporting of methane emissions from both existing and new oil and gas production facilities. Similar regulations applicable to oil and gas facilities have been promulgated in Colorado.

Furthermore, we have been and could be impacted in the future by the effects of winter weather and the weatherization of our facility equipment and the equipment of counterparties in anticipation of future climactic events. For example, in the winter of 2022, certain of our surface facilities in South Texas were impacted by abnormal winter conditions that temporarily adversely affected our production. In addition, in response to Winter Storm Uri, the TRC was directed to adopt rules requiring certain natural gas processing, storage, and pipeline facility operators experiencing major or repeated weather-related forced interruptions of service to, among other things, engage an independent party to assess the operator’s weatherization plans, procedures and operations, and submit the assessment to the TRC. In August 2022, the TRC adopted the Weather Emergency Preparedness Standards Rule, which requires critical gas facilities on the state’s Electricity Supply Chain, including natural gas processing, storage, and pipeline facilities, to (i) weatherize to help ensure sustained operations during a weather emergency; (ii) correct known issues that caused weather-related forced stoppages; and (iii) contact the TRC if a facility sustains a weather-related forced stoppage during a weather emergency. In addition, weather-related forced stoppages at processing, storage and pipeline facilities operated by counterparties with which we contract for services may also adversely affect our operations and financial results.

Internationally, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emission reduction targets every five years after 2020. Although the United States had withdrawn from the agreement, President Biden has signed executive orders recommitting the United States to the agreement and, in April 2021, announced a target of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again in Glasgow at the COP26, during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-CO2 GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. At COP27 in November 2022, countries reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase out of inefficient fossil fuel subsidies. The United States also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. Although no firm commitment or timeline to phase out or phase down all fossil fuels was made at COP27, there can be no guarantees that countries will not seek to implement such a phase out in the future. The impacts of these orders, pledges, agreements any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, COP27 or other international conventions cannot be predicted at this time.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by the recently elected administration. These have included promises to limit emissions and curtail the production of oil and gas on federal lands, such as through the cessation of leasing public land for hydrocarbon development. For example President Biden has issued several executive orders focused on addressing climate change, including items that may impact our costs to produce, or demand for, oil and gas. Additionally, in November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; and reducing non-CO2 GHG emissions, such as methane and nitrous oxide. The Biden Administration is also considering revisions to the leasing and permitting programs for oil and gas development on federal lands. For more information, see our regulatory disclosure in "Items 1 and 2. Business and Properties—Legislative and regulatory environment—Hydraulic fracturing. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emission limitations for oil and gas facilities. Litigation risks are also increasing, as a number of parties have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed climate change or alleging that companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.

There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. 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. For example, at COP26, the GFANZ announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, President Biden signed an executive order calling for the development of a “climate finance plan” and, separately, in late 2020, the Federal Reserve announced that it had joined the NGFS, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. In September 2022, the Federal Reserve announced that six of the U.S.’ largest banks would participate in a pilot climate scenario analysis exercise, to enhance the ability of firms and supervisors to measure and manage climate-related financial risk. Released in January 2023, the pilot exercise is designed to analyze the impact of both physical and transition risks related to climate change on specific assets of the banks' portfolio. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. Additionally, the SEC published a proposed rule requiring climate-related disclosures from registrants, including data on Scope 1 and 2 GHG emissions and, in some cases, Scope 3 emissions, as well as any set climate-related targets and goals. A final rule is expected to be released in the second quarter of 2023. Although the final form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements. We also cannot predict how such disclosures may be considered by financial institutions and investors when making investments decisions, and it is possible that we could face increased costs or restrictions on our access to capital.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from oil and natural gas producers, such as ourselves or our operators, or otherwise restrict the areas in which we may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for or erode value for, the oil and natural gas that we produce. Additionally, political, litigation, and financial risks may result in our restricting or canceling oil and natural gas production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing our ability to continue to operate in an economic manner. Moreover, climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events (including storms, wildfires, and other natural disasters) or changes in meteorological and hydrological patterns, that could adversely impact our operations, as well as those of our operators and their supply chains. Such physical risks may result in damage to our facilities or otherwise adversely impact our operations, such as if we become subject to water use curtailments in response to drought, or demand for our products, such as to the extent warmer winters reduce the demand for energy for heating purposes. Such physical risks may also impact our supply chain or infrastructure on which we rely to produce or transport our products. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil, natural gas and NGLs from dense subsurface rock formations. We and the operators of our properties regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. The U.S. Congress from time to time has considered legislation to amend the SDWA to remove the exemption currently available to hydraulic fracturing, which would place additional regulatory burdens upon hydraulic fracturing operations including requirements to obtain a permit prior to commencing operations adhering to certain construction requirements, to establish financial assurance, and to require reporting and disclosure of the chemicals used in those operations. This legislation has not passed.

Hydraulic fracturing (other than that using diesel) is currently generally exempt from regulation under the SDWA’s UIC program and is typically regulated by state oil and natural gas commissions or similar agencies. However, several federal agencies have asserted regulatory authority or pursued investigations over certain aspects of the process. For example, in June 2016, the EPA published an effluent limitations guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants.

Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. To date, EPA has taken no further action in response to the December 2016 report.

In addition, the BLM finalized a rule in March 2015 for hydraulic fracturing activities on federal and Tribal lands that requires public disclosure of chemicals used in hydraulic fracturing, confirmation that the wells used in fracturing operations meet proper construction standards and development of plans for managing related flowback water. While the BLM rescinded these regulations in 2017, which rescission was upheld, these regulations may be reconsidered by the Biden Administration. The Biden Administration may also pursue further restriction of hydraulic fracturing and other oil and gas development on federal lands; for more information, see our regulatory disclosure in "Items 1 and 2. Business and Properties—Legislative and regulatory environment—Hydraulic fracturing."

In addition, some states, including Texas, have adopted, and other states are considering adopting, regulations that restrict or could restrict hydraulic fracturing in certain circumstances and that require the disclosure of the chemicals used in hydraulic fracturing operations. Further, state and local governmental entities have exercised the regulatory powers to regulate, curtail or in some cases prohibit hydraulic fracturing. For example, Colorado has adopted more stringent setbacks for oil and gas development. In California, Senate Bill No. 1137 was signed into law on September 16, 2022, which establishes 3,200 feet as the minimum distance between new oil and gas production wells and certain sensitive receptors such as home, schools or parks effective January 1, 2023. However, on February 3, 2023, the Secretary of State of California certified a requisite number of signatures collected by proponents of a voter referendum, thereby qualifying the Bill for the November 2024 ballot. Accordingly, Senate Bill No. 1137 is stayed until it is put to a vote. New laws or regulations that impose new obligations on, or significantly restrict hydraulic fracturing, could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect our determination of whether a well is commercially viable and increase our cost of doing business. Such increased costs and any delays or curtailments in our production activities could have a material and adverse effect on our business, prospects, financial condition, results of operations and liquidity.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, such as those restrictions imposed under the federal ESA and MBTA. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species, such as the dunes sagebrush lizard, lesser prairie chicken, and greater sage grouse, that potentially could be listed as threatened or endangered under the ESA may exist. A review is currently pending to determine whether the dunes sagebrush lizard should be listed and, in November 2022, the FWS listed two distinct population segments of the lesser prairie-chicken under the ESA. Additionally, the Biden Administration has taken action to broaden enforcement under the ESA, including expanding the definition of “critical habitat.” The designation of previously unprotected species in areas where we operate as threatened or endangered, a recategorization of a species from threatened to endangered, or an expansion of areas designated as “critical habitat” could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration, development and production activities that could have an adverse impact on our ability to develop and produce our reserves. To the extent species are listed under the ESA or similar laws, or previously unprotected species are designated as threatened or endangered in areas where our properties are located, operations on those properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon.

Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us or our operators. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.

Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated

therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. We may also announce participation in, or certification under, various third-party ESG frameworks in an attempt to improve our ESG profile, but such participation or certification may be costly and may not achieve the desired results. Additionally, while we may announce various voluntary ESG targets, such targets are aspirational. We may not be able to meet such targets in the manner or on such a timeline as initially contemplated, including but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent we meet such targets, it may be achieved through various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. However, we cannot guarantee that there will be sufficient offsets available for purchase given the increased demand from numerous businesses implementing net

zero goals, or that offsets we do purchase will successfully achieve the emissions reductions they represent. Also, despite these aspirational goals and any other actions taken, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our access to and costs of capital. Also, institutional lenders may decide not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects. Additionally, to the extent ESG matters

negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations. ESG matters may also impact our suppliers and customers, which may ultimately have adverse impacts on our operations.

Furthermore, public statements with respect to ESG matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential ESG benefits. For example, in March 2021, the SEC established the Climate and ESG Task Force in the Division of Enforcement to identify and address potential ESG-related misconduct, including greenwashing. Certain non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain ESG-statements, goals or standards were misleading, false or otherwise deceptive. As a result, we may face increased litigation risk from private parties and governmental authorities related to our ESG efforts. In addition, any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. In addition, certain institutions have also undertaken anti-ESG initiatives focused around their view of the politicization of ESG issues. We could face increasing costs as we attempt to comply with and navigate further regulatory ESG-related focus and scrutiny.

If we are unable to make capital expenditures or acquisitions because we are unable to obtain capital or financing on satisfactory terms, we may experience a decline in our oil and gas production rates and reserves. We are partially dependent on external capital sources to provide financing for certain projects. The availability and cost of these capital sources is cyclical, and these capital sources may not remain available, or we may not be able to obtain financing at a reasonable cost in the future. For example, due to the high levels of inflation in the U.S., the Federal Reserve and other central banks increased interest rates multiple times in 2022 and 2023 and have indicated that such increases will continue. Such increased interest rates may increase the cost of capital and prevent us from being able to obtain debt financing at favorable rates, or at all, which would materially impact our operations. In addition, conditions in the global capital markets have been volatile due to the conflict in Ukraine, the COVID-19 pandemic or otherwise, making terms for certain types of financing difficult to predict, and in certain cases, resulting in certain types of financing being unavailable. If our revenues decline as a result of lower oil, gas or NGL prices, operating difficulties, declines in production or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. Our failure to obtain additional financing could result in a curtailment of our operations or not make acquisitions, which in turn could lead to a possible reduction in our oil or gas production, reserves and revenues, not having sufficient liquidity to meet future financial obligations and could negatively impact our results of operations.

We have incurred significant additional indebtedness during recent periods. Our additional indebtedness may impair our ability to raise further capital, including to expand our business, pursue strategic investments, and take advantage of financing or other opportunities that we believe to be in the best interests of the Company and our shareholders.

Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our indebtedness depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. Our business may not continue to generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we may be required to adopt one or more alternatives, such as selling assets, curtailing spending, restructuring debt, or obtaining additional equity capital on terms that may be onerous or highly dilutive. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at such time. Our additional indebtedness may also impact our ability to service our debt and to comply with financial covenants and the other terms of our relevant credit arrangements, in which case our lenders might pursue available remedies up to and including terminating our credit arrangements and foreclosing on available collateral.

Our primary sources of liquidity are borrowings under our Revolving Credit Facility and cash from operations. The borrowing base under our Revolving Credit Facility is subject to semi-annual redeterminations which occur on or about April 1 and Oct 1 of each year. During a borrowing base redetermination, the lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our Revolving Credit Facility. The borrowing base depends on, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing our loan, many of which factors are beyond our control.

Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.

We are exposed to interest rate risk associated with borrowings under our Revolving Credit Facility. Borrowings under the Revolving Credit Facility bear interest at either a U.S. dollar alternative base rate (based on the prime rate, the federal funds effective rate or an adjusted SOFR(as defined below)), plus an applicable margin or SOFR, plus an applicable margin, at the election of the borrowers. As a result of our variable interest debt, our results of operations could be adversely affected by increases in interest rates.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to maintain internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving internal controls, could harm our operating results or cause us to fail to meet our

reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A Common Stock.

Our Class A Common Stock trades on the NYSE under the ticker "CRGY." However, an active, liquid and orderly trading market for our Class A Common Stock may not be maintained. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. Consequently, you may not be able to sell shares of our Class A Common Stock at prices equal to or greater than the assumed price attributable to such shares. The stock markets in general have experienced extreme volatility that has often been unrelated or disproportionate to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our Class A Common Stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us could result in very substantial costs, divert management’s attention and resources and harm our business, operating results and financial condition.

We may sell additional shares of our Class A Common Stock in subsequent offerings. In addition, subject to certain limitations and exceptions, OpCo Unit Holders may redeem their OpCo Units (together with a corresponding number of shares of our Class B Common Stock) for shares of our Class A Common Stock (on a one-for-one basis, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions) and then sell those shares of our Class A Common Stock. At December 31, 2022, we have 48,282,163 outstanding shares of Class A Common Stock and 118,645,323 outstanding shares of Class B Common Stock. Independence’s former owners own all of the outstanding shares of our Class B Common Stock, representing approximately 71% of our total outstanding common stock. All such shares may be sold into the market in the future.

For example, we recently registered the offer and sale of up to an aggregate of $700 million of our securities and the resale of 128,927,826 shares of our Class A Common Stock by certain selling stockholders. In addition to sales pursuant to such registration by selling stockholders, certain of our significant stockholders, including such selling stockholders, may distribute shares of our securities that they hold to their investors who themselves may then sell into the public market. Any sales of such securities may depress the price of our shares. Furthermore, we filed a registration statement with the SEC on Form S-8 providing for the registration of 947,483 shares of our Class A Common Stock issued or reserved for issuance under the Equity Incentive Plan. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 have been made available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our Class A Common Stock or securities convertible into Class A Common Stock or the effect, if any, that future issuances and sales of shares of our Class A Common Stock will have on the market price of our Class A Common Stock. Sales of substantial amounts of our Class A Common Stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A Common Stock.

The trading market for our Class A Common Stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of us or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover us downgrades our Class A Common Stock or if our operating results do not meet their expectations, the trading price of our Class A Common Stock could decline.

We enter into derivative instrument contracts for a significant portion of our existing production. We plan to continue the practice of entering into hedging arrangements to reduce near-term exposure to commodity prices, protect cash flow and returns and maintain our liquidity.

Our hedging contracts may result in substantial gains or losses. For example, we had realized commodity derivative losses of $779.3 million in 2022; however, there can be no assurance that we will not realize additional future losses due to our hedging activities. In addition, if we enter into any hedging contracts and experience a sustained material interruption in our production, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity.

Our ability to use hedging transactions to protect us from future oil and natural gas price declines will be dependent upon oil and natural gas prices at the time we enter into future hedging transactions and our future levels of hedging and, as a result, our future net cash flows may be more sensitive to commodity price changes. In the future, we may be unable to hedge anticipated production volumes on attractive terms or at all, which would subject us to further potential commodity price uncertainty and could adversely affect our net cash provided by operating activities, financial condition and results of operations.

Our price hedging strategy and future hedging transactions will be determined at our discretion. The prices at which we hedge our production in the future will be dependent upon commodities prices at the time we enter into these transactions, which may be substantially higher or lower than current prices. Accordingly, our price hedging strategy may not protect us from significant declines in prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price fluctuations.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. This risk of counterparty non-performance is of particular concern given the historical disruptions that have occurred in the financial markets and the significant decline in oil and natural gas prices which could lead to sudden changes in a counterparty’s liquidity, and impair their ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of our hedge providers or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities.

During periods of falling commodity prices, our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

We currently anticipate that the only source of our earnings will be cash distributions from our operating subsidiaries. The amount of cash that our operating subsidiaries can distribute each quarter to their owners principally depends upon the amount of cash they generate from their operations, which will fluctuate from quarter to quarter based on, among other things:

In addition, we do not wholly own all of our operating subsidiaries. As a result, if such operating subsidiaries make distributions, including tax distributions, they will also have to make distributions to their noncontrolling interest owners.

We are a holding company and have no material assets other than our ownership interest in OpCo. We will have no independent means of generating revenue or cash flow. To the extent OpCo has available cash and subject to the terms of any current or future indebtedness agreements, we intend to cause OpCo (i) to make pro rata cash distributions to holders of OpCo Units, including us, in an amount sufficient to allow us to pay our taxes and to make payments under the Management Agreement and (ii) to reimburse us for our corporate and other overhead expenses. We generally expect OpCo to fund such distributions out of available cash. When OpCo makes distributions, the holders of OpCo Units will be entitled to receive proportionate distributions based on their interests in OpCo at the time of such distribution. To the extent that we need funds and OpCo or its subsidiaries are restricted from making such distributions or payments under applicable law or regulation or under the terms of any current or future indebtedness agreements, or are otherwise unable to provide such funds, our liquidity and financial condition could be materially adversely affected.

Moreover, because we have no independent means of generating revenue, our ability to make tax payments and payments under the Management Agreement is dependent on the ability of OpCo to make distributions to us in an amount sufficient to cover our tax obligations and obligations under the Management Agreement. This ability, in turn, may depend on the ability of OpCo’s subsidiaries to make distributions to it. The ability of OpCo, its subsidiaries and other entities in which it directly or indirectly holds an equity interest to make such distributions will be subject to, among other things, (i) the applicable provisions of Delaware law (or other applicable jurisdiction) that may limit the amount of funds available for distribution and (ii) restrictions in relevant debt instruments issued by OpCo or its subsidiaries and other entities in which it directly or indirectly holds an equity interest.

Because the Preferred Stockholder is the sole owner of our Non-Economic Series I Preferred Stock and accordingly has the exclusive right to appoint our Board of Directors, we are a controlled company under the Sarbanes-Oxley Act and NYSE rules. A controlled company does not need its board of directors to have a majority of independent directors or to form an independent compensation or nominating and corporate governance committee. As a controlled company, we will remain subject to rules of the Sarbanes-Oxley Act and the NYSE that require us to have an audit committee composed entirely of independent directors.

If at any time we cease to be a controlled company, we will take all action necessary to comply with the Sarbanes-Oxley Act and NYSE rules, including by appointing a majority of independent directors to the our Board of Directors and ensuring we have a compensation committee and a nominating and corporate governance committee, each composed entirely of independent directors, subject to a permitted “phase-in” period.

Our Certificate of Incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law, our Certificate of Incorporation or our Bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our restated Certificate of Incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

Our Preferred Stockholder is the sole holder of our Non-Economic Series I Preferred Stock and is expected to retain its ownership of our Non-Economic Series I Preferred Stock until such time as it ceases to own a number of shares of our common stock equal to or greater than 50% of the shares of our Class A Common Stock and our Class B Common Stock it owns, subject to certain exceptions. Our Non-Economic Series I Preferred Stock entitles the holder thereof to appoint our entire Board of Directors and to certain other to approval rights with respect to certain fundamental corporate actions, including debt incurrence in excess of 10% of then outstanding indebtedness, significant equity raises, preferred equity issuances, adoption of a shareholder rights plan, amendments of our certificate of incorporation and certain sections of its bylaws, a sale of all or substantially all of our assets, mergers involving us, removals of our Chief Executive Officer and the liquidation or dissolution of us. Unlike common equity in traditional corporate structures, holders of our common stock will not vote for the election of directors. As a result, holders of our common stock will have less ability to influence our business than would the holders of common equity in a traditional corporate structure.

Given its ownership of the our Non-Economic Series I Preferred Stock, the Preferred Stockholder would have to approve any potential acquisition of us. The existence of a controlling shareholder may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other shareholders to approve transactions that they may deem to be in our best interests. Moreover, the Preferred Stockholder’s controlling ownership position may adversely affect the trading price of our Class A Common Stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling shareholder, whether due to a decreased likelihood of a sale of us at a premium to the then-existing trading price of our Class A Common Stock or otherwise.

To the fullest extent permitted by applicable law, our Certificate of Incorporation contains provisions limiting the duties owed by the Preferred Stockholder and contain provisions allowing the Preferred Stockholder to favor its own interests and the interests of its controlling persons over us and the holders of our common stock. Our Certificate of Incorporation contains provisions stating that the Preferred Stockholder is under no obligation to consider the separate interests of the other

stockholders (including the tax consequences to such stockholders) in deciding whether or not to authorize us to take (or decline to authorize us to take) any action as well as provisions stating that the Preferred Stockholder shall not be liable to the other stockholders for damages or equitable relief for any losses, liabilities or benefits not derived by such stockholders in connection with such decisions.

The “corporate opportunity” doctrine provides that corporate fiduciaries, as part of their duty of loyalty to the corporation and its stockholders, may not take for themselves an opportunity that in fairness should belong to the corporation. As such, a corporate fiduciary may generally not pursue a business opportunity which the corporation is financially able to undertake and which, by its nature, falls into the line of the corporation’s business and is of practical advantage to it, or in which the corporation has an actual or expectant interest, unless the opportunity is disclosed to the corporation and the corporation determines that it is not going to pursue such opportunity. Section 122(17) of the DGCL, however, expressly permits a Delaware corporation to renounce in its certificate of incorporation any interest or expectancy of the corporation in, or in being offered an opportunity to participate in, specified business opportunities or specified classes or categories of business opportunities that are presented to the corporation or its officers, directors or stockholders.

Our Certificate of Incorporation contains a provision that, to the maximum extent permitted under the law of the State of Delaware, we renounce any interest or expectancy in, or in being offered an opportunity to participate in, business opportunities that are from time to time presented to its officers, directors, the Preferred Stockholder or any partner, manager, member, director, officer, stockholder, employee or agent or affiliate of any such holder. We believe that this provision, which is intended to provide that certain business opportunities are not subject to the “corporate opportunity” doctrine, is appropriate, as the Preferred Stockholder and its affiliates invest in a wide array of companies, including companies with businesses similar to us. As a result of this provision, we may be not be offered certain corporate opportunities which could be beneficial to us and our stockholders.

We intend to operate such that OpCo does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. A “publicly traded partnership” is a partnership the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, redemptions of OpCo Units pursuant to the Redemption Right or other transfers of OpCo Units could cause OpCo to be treated as a publicly traded partnership. Applicable U.S. Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and we intend to operate such that redemptions or other transfers of OpCo Units qualify for one or more such safe harbors. For example, we intend to limit the number of holders of OpCo Units, and the OpCo LLC Agreement, provides for limitations on the ability of holders of OpCo Units to transfer their OpCo Units and provides us, as the managing member of OpCo, with the right to impose restrictions (in addition to those already in place) on the ability of holders of OpCo Units to redeem their OpCo Units pursuant to the Redemption Right to the extent we believe it is necessary to ensure that OpCo will continue to be treated as a partnership for U.S. federal income tax purposes.

If OpCo were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, significant tax inefficiencies might result for us and OpCo, including as a result of our inability to file a consolidated U.S. federal income tax return with OpCo.

U.S. federal, state and local and non-U.S. tax laws, policies, statutes, rules, regulations or ordinances could be interpreted, changed, modified or applied adversely to us, in each case, possibly with retroactive effect, and may have an adverse effect on our business, results of operations, financial condition and cash flows. In the past, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and natural gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. These

proposed changes in the U.S. tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flow.

As of December 31, 2022, we had a net operating loss, or NOL, carry forward of approximately $121 million for federal and state income tax purposes, most of which is already limited by Section 382 of the Code. If we were to experience a further “ownership change,” as determined under Section 382 of the Code, our ability to offset taxable income arising after the ownership change with NOLs generated prior to the ownership change would be limited, possibly substantially. In general, an ownership change would establish an annual limitation on the amount of our pre-change NOLs that we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by an interest rate periodically promulgated by the IRS referred to as the long-term tax-exempt rate. In general, an ownership change will occur if there is a cumulative increase in the ownership of our stock totaling more than 50 percentage points by one or more “5% shareholders” (as defined in the Code) at any time during a rolling three-year period.

We are heavily dependent on our information systems and computer based programs, including with respect to our well operations information, seismic data, electronic data processing and accounting data, and the availability and integrity of these programs and systems are essential for us to conduct our business and operations. If any of such programs or systems were to be subject to a cyberattack, to fail or to create erroneous information in our hardware or software network infrastructure, whether due to telecommunications failures, human error, natural disaster, fire, sabotage, hardware or software malfunction or defects, computer viruses, intentional acts of vandalism or terrorism or similar acts or occurrences, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material and adverse effect on our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Furthermore, beginning in February 2022, the United States and other countries began imposing meaningful sanctions targeting Russia as a result of actions taken by Russia in Ukraine. These sanctions and actions by Russia in response thereto may cause disruptions in international supply chains, financial activities and operations, the full costs, burdens, and limitations of which are currently unknown and may become significant. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

We face various security threats, including cyber security threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist or criminal actors. The potential for such security threats has subjected our operations to increased risks that could have a material and adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring, particularly given the unpredictability of the timing, nature, and scope of IT breaches, attacks, disruptions and other incidents. If any of these incidents were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cyber security attacks in particular are becoming more sophisticated and include, but are not limited to, installation

of malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. For example, in May 2021, Colonial Pipeline's digital systems were infected by a ransomware attack that caused the shutdown of the pipeline for several days and the payment of an approximate $4.4 million ransom. The U.S. government also has issued public warnings that indicate that energy assets might be specific targets of cybersecurity threats. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability. While we maintain insurance that covers certain security and privacy breaches, we may not carry appropriate insurance or maintain sufficient coverage to compensate for all potential liability, and such insurance may not continue to be available to us on reasonable terms, if at all.

The regulatory environment surrounding data privacy and protection is constantly evolving and can be subject to significant change. New laws and regulations governing data privacy and the unauthorized disclosure of personal or confidential information pose increasingly complex compliance challenges and could potentially elevate our costs. Any failure to comply with these laws and regulations could result in significant penalties and legal liability. We continue to monitor and assess the impact of these laws, which in addition to penalties and legal liability, could impose significant costs for investigations and compliance, require us to change our business practices and carry significant potential liability for our business should we fail to comply with any such applicable laws.

We rely on certain intellectual property rights in the operation of our business. The market success of our operations will depend, in part, on our ability to obtain and enforce our proprietary rights in certain technologies, to preserve rights in our trade secret and non-public information, and to operate without infringing the proprietary rights of others. We may not be able to successfully preserve these intellectual property rights in the future and these rights could be invalidated, circumvented, or challenged. If any of our intellectual property rights are determined to be invalid or unenforceable, our competitive advantages could be significantly reduced, allowing competition for our customer base to increase. The failure of our Company to protect our proprietary information and any successful intellectual property challenges or infringement proceedings against us could adversely affect our competitive position. The tools, techniques, methodologies, programs, and components we use in the operation of our business may infringe, or be alleged to infringe, upon the intellectual property rights of others. Infringement claims generally result in significant legal and other costs, and may distract management from running our core business. Royalty payments under a license from third parties, if available, or an obligation to redesign our operations, would increase our costs. Any of these developments could have a material adverse effect on our business, financial condition, and results of operations.

Similar to many oil and natural gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have a material and adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, resolution of one or more such proceedings could result in liability, loss of contractual or other rights, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

We are subject to risk of loss resulting from nonpayment or nonperformance by our customers. Substantially all of our accounts receivable result from our oil and natural gas sales to a small number of third parties in the energy industry. This concentration of customers may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks. If any of our key customers default on their obligations to us, our financial results could be materially and adversely affected.

We regularly review our asset base to assess the market value versus holding value of existing assets with a view to optimizing returns on deployed capital. Our ability to dispose of assets could be affected by various factors, including the availability of buyers willing to purchase assets at prices acceptable to us. Sellers typically retain certain liabilities or agree to indemnify buyers for certain matters. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a sale, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.

Our operations are subject to catastrophic losses, operational hazards, unforeseen interruptions and other disruptive risks such as natural disasters, adverse weather, accidents, maritime disasters (including those involving marine vessels/terminals), fires, explosions, hazardous materials releases, terror or cyberattacks, domestic vandalism, power failures, mechanical failures and other events beyond our control. These events could result in an injury, loss of life, property damage or destruction, as well as a curtailment or an interruption in our operations and may affect our ability to meet marketing commitments.

None.

The Company, as an owner and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage that is customary in the industry, although the Company is not fully insured against all environmental risks.

Not applicable

Our Class A Common Stock is listed and traded on the NYSE under the ticker symbol "CRGY." As of January 31, 2022, we had 101 Class A common stock shareholders of record and two Class B common stock shareholders of record. Our future dividends depend on our level of earnings, financial requirements and other factors and will be subject to approval by our Board of Directors, applicable law and the terms of our existing debt documents, including the Revolving Credit Facility and the indentures governing the 2026 Notes (as defined below) and the 2028 Notes (as defined below; together with the 2026 Notes, the "Senior Notes").

We had no sales of unregistered equity securities during the period covered by this Annual Report that were not previously reported in a Current Report on Form 8-K or Quarterly Report on Form 10-Q.

Our approach employs a unique business model that combines an investor mindset and deep operational expertise to pursue a cash flow-based investment mandate focused on operated working interests with an active risk management strategy. We pursue our strategy through the production, development and acquisition of oil, natural gas and NGL reserves.

During the last several years, prices of crude oil, natural gas and NGLs have experienced periodic downturns and sustained volatility. In particular, the global spread of the COVID-19 virus during 2020 and 2021 had a negative impact on the global demand for oil and natural gas and caused significant commodity market volatility. While the increase in domestic vaccination programs and reduced spread of the COVID-19 virus has contributed to an improvement in the economy and higher realized prices for commodities, the current price environment remains uncertain as responses to the COVID-19 pandemic and newly emerging variants of the virus continue to evolve. Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the COVID-19 pandemic and related market conditions will persist. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.

In addition, in February 2022, Russia launched a large-scale invasion of Ukraine that has led to significant armed hostilities. As a result, the United States, the United Kingdom, the member states of the European Union and other public and private actors have levied severe sanctions on Russian financial institutions, businesses and individuals. This conflict, and the resulting sanctions, have contributed to significant increases and volatility in the price for oil and natural gas, with the posted price for WTI reaching a high of over $120 per barrel in 2022. Such volatility may lead to a more difficult investing and planning environment for us and our customers. While the near-term impact of these events resulted in higher oil and gas prices in 2022, the geopolitical and macroeconomic consequences of this invasion and associated sanctions cannot be predicted, and such events, or any further hostilities in Ukraine or elsewhere, could severely impact the world economy and may adversely affect our financial condition. Furthermore, the United States has experienced a significant inflationary environment in 2022 that, along with international geopolitical risks, has contributed to concerns of a potential recession that has caused oil and gas prices to retreat from their earlier highs in 2022 and has created further volatility.

Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. The U.S. inflation rate has been steadily increasing since 2021. These inflationary pressures have resulted in and may result in additional increases to the costs of our oilfield goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates, and to the extent elevated inflation remains, we may experience further cost increases for our operations, including oilfield services, labor costs and equipment if our drilling activity increases. Higher oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to recover higher costs through higher oil and natural gas prices and revenues, would negatively impact our business, financial condition and results of operations. See "Part I., Item 1A. Risk Factors—Risks related to the oil and natural gas industry and our operations—Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise."

In August 2022, IRA 2022 was signed into law. The IRA 2022 contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. These incentives could further accelerate the transition of the U.S. economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives, which could decrease demand for the oil and gas we produce and consequently materially and adversely affect our business and results of operations. In addition, the IRA 2022 imposes a federal fee on the emission of GHGs through a methane emissions charge, including onshore petroleum and natural gas production. The methane emissions charge will start in calendar year 2024 and the fee is based on certain thresholds established in the IRA 2022. The methane emissions charge could increase our operating costs and adversely affect our business and results of operations. See "Part I., Item 1A. Risk Factors" for additional information. Finally, the IRA 2022 includes a new corporate alternative minimum tax of 15% on the adjusted financial statement income ("AFSI") of corporations with average AFSI exceeding $1.0 billion over a three-year period. While we are evaluating the impact of the new corporate alternative minimum tax will have, we do not believe that it will have a material impact on our near-term taxes.

In September 2022, Independence Energy Aggregator L.P. ("Aggregator"), the entity through which certain affiliated entities hold their interests in us, exchanged 6.3 million units representing membership interests in OpCo (together with a corresponding number of shares of our Class B Common Stock) for shares of our Class A Common Stock and agreed to sell 5.75 million shares of our Class A Common Stock (the "Offering") at a price to the public of $15.00 per share, or a net price of $14.10 per share after deducting the underwriters' discounts and commissions. We did not receive any cash proceeds from the Offering. Concurrent with the closing of the Offering, we repurchased an aggregate of approximately 2.6 million OpCo Units from PT Independence for $36.2 million and cancelled a corresponding number of shares of our Class B Common Stock (the "Concurrent OpCo Unit Purchase," and, together with the Offering, the "Equity Transactions"). As a result of the Equity Transactions, the total number of shares of our Class A Common Stock increased by 6.3 million shares, including 0.6 million shares of our Class A Common Stock that were not included as part of the Offering but rather issued in exchange for shares of Class B Common Stock and distributed in-kind by Aggregator. to affiliates, and the number of shares of our Class B Common Stock decreased by approximately 8.9 million. After the Equity Transactions, shares of our Class A Common Stock represent approximately 29% of the outstanding shares of Class A Common Stock and Class B Common Stock, taken together, and we own approximately 29% of the outstanding OpCo Units. Redeemable noncontrolling interests decreased by $158.1 million while APIC increased by $121.8 million as a result of the Equity Transactions and to reflect the new ownership of OpCo.

Subsequent to the closing of the Uinta Transaction, we settled certain acquired oil commodity derivative positions and entered into new commodity derivative contracts for 2022 with a swap price of $75 per barrel for a net cost of $54.1 million, including restructuring fees, during the three months ended March 31, 2022.

In December 2021, we completed a series of transactions, pursuant to which the business of Contango and the business of Independence combined under a new publicly traded holding company named "Crescent Energy Company." Our Class A common stock, par value $0.0001 per share (“Class A Common Stock") is listed on the NYSE under the symbol “CRGY.” The combined company is structured as an “Up-C,” with all of our assets and operations (including those of Contango) indirectly held by our operating subsidiary, OpCo. Crescent Energy Company is a holding company, the sole material asset of which consists of OpCo Units, and is responsible for all operational, management and administrative decisions related to OpCo’s business. We are the sole managing member of OpCo. Crescent consolidates the financial results of OpCo and its subsidiaries. Former Contango shareholders own shares of Class A Common Stock, which have both voting and economic rights. The former owners of our predecessor, Independence Energy LLC, own economic, non-voting OpCo Units and corresponding shares of Class B common stock, par value $0.0001 per share ("Class B Common Stock," together with Class A Common Stock, the "Common Stock"), which shares of Class B Common Stock have voting (but no economic) rights. OpCo Units may be redeemed or exchanged for Class A Common Stock or, at our election, cash on the terms and conditions set forth in the Amended and Restated Limited Liability Company Agreement of OpCo.

In connection with the Merger Transactions, we underwent a reorganization (the “Crescent Reorganization”), whereby Independence merged with and into OpCo (the “Isla Merger”). The financial statements include the accounts of Independence

from the date of the Isla Merger, which is the date the Company obtained a controlling financial interest in Independence on a consolidated basis. Because the Isla Merger resulted in a change in the reporting entity, and in order to furnish comparative financial information prior to the Isla Merger, our financial statements have been retrospectively recast to reflect the historical accounts of Independence, our accounting predecessor (the "Predecessor"), on a combined basis.

In May 2021, certain of our consolidated subsidiaries redeemed the noncontrolling equity interests held in such subsidiaries by a third-party investor in exchange for the third-party investor’s proportionate share of the underlying oil and natural gas interests held by its consolidated subsidiaries (the "Noncontrolling Interest Carve-out"). Additionally, the third-party investor contributed cash of approximately $35.5 million to repay its proportionate share of the underlying debt outstanding under the revolving credit facilities of certain of our subsidiaries (the "Prior Credit Agreements") and other liabilities. The percentage ownership of these certain consolidated subsidiaries owned by the third-party investor ranges from 2.21% to 7.38%.

In April 2021, certain minority investors exchanged 100% of their interests in our Barnett basin natural gas assets for 9,508 of Class A units of our Predecessor, representing 0.77% of our consolidated ownership pursuant to the April 2021 Exchange. Since we already consolidate the results of these assets, this transaction was accounted for as an equity transaction and reflected as a reclassification from noncontrolling interests to members’ equity with no gain or loss recognized on the April 2021 Exchange.

In March 2021, we acquired a portfolio of oil and natural gas mineral assets located in the DJ Basin from an unrelated third-party operator for total consideration of $60.8 million (the "DJ Basin Acquisition"). The DJ Basin Acquisition was funded using cash on hand and borrowings under our Prior Credit Agreements. We accounted for the DJ Basin Acquisition as an asset acquisition.

In August 2020, we consummated the Titan Acquisition, pursuant to which we acquired of all of the outstanding membership interests in Liberty Energy LLC (and the oil and natural gas assets owned thereby) pursuant to the Contribution Agreement, dated as of July 19, 2020, by and among Independence Energy LLC, Liberty Energy Holdings, LLC (“Liberty Holdco”) and the other parties thereto, in consideration for the issuance of certain membership interests in Independence to an entity substantially owned by Liberty Holdco. Subsequent to the Titan Acquisition, we changed the name of Liberty Energy, LLC to Titan. Titan owns certain working interests in non-operated producing and non-producing oil and natural gas properties in the Permian, DJ and Eagle Ford Basins, which includes a 50% interest in the DJ Basin Erie Hub Gathering System. As a part of the Titan Acquisition, during the year ended December 31, 2020, we transferred $455.1 million of equity consideration in the form of 0.4 million Class A units of our Predecessor.

In November 2022, we entered into a definitive purchase and sale agreement with an unaffiliated third party to sell certain of our non-core producing properties and related oil and natural gas leases in Ector County in the Permian Basin in exchange for cash consideration, subject to customary purchase price adjustments, of $80.0 million. We closed the divestiture in December 2022 and recorded a loss of $0.9 million during the year ended December 31, 2022.

In April 2022, our equity method investment, Exaro Energy III, LLC ("Exaro"), entered into a purchase and sale agreement to sell its operations in the Jonah Field in Wyoming. During the year ended December 31, 2022, we received a distribution of $6.8 million primarily as a result of the sale.

In February 2022, we contributed all of the assets and prospects in the Gulf of Mexico formerly owned by Contango to Chama Energy LLC ("Chama") in exchange for a 9.4% interest in Chama, which interest was valued at $3.8 million. As a result, we derecognized the assets and liabilities that were contributed to Chama from our consolidated balance sheets and recorded an equity method investment for our interest in Chama, as well as a $4.5 million gain related to the deconsolidation of these assets and liabilities. John Goff, the Chairman of our Board of Directors, holds an approximate interest of 17.5% in Chama, and the remaining interests are held by other investors. Pursuant to the Limited Liability Company Agreement of Chama, we may be required to fund certain workover costs, and we will be required to fund plugging and abandonment costs related to the producing assets we contributed to Chama.

In December 2021, we entered into a purchase and sale agreement with an unaffiliated third-party that encompassed the sale of certain producing properties and oil and natural gas leases in Claiborne Parish, Louisiana in exchange for cash consideration, net of closing adjustments, of $4.3 million.

In May 2021, we executed a purchase and sale agreement with an unaffiliated third-party that encompassed the sale of certain producing properties and oil and natural gas leases in the Arkoma Basin in exchange for cash consideration, net of closing adjustments, of $22.1 million. We recognized a $8.8 million gain on sale of assets in our combined and consolidated statements of operations for the year ended December 31, 2021, as a result of the transaction.

We strive to be good stewards of others’ assets: our investors’ capital, the environment and the communities in which we operate. We believe that this stewardship, and our success, requires an alignment with the interests of our stakeholders including our employees, investors, customers, suppliers and society at large. We view exceptional sustainability performance as an opportunity to differentiate Crescent from its peers, mitigate risks and strengthen operational performance as well as benefit our stakeholders and the communities in which we operate. In September 2022, we released our 2021 ESG report. The report included benchmarks for measuring future performance, consistent with Crescent's commitment to aligning with the SASB and Task Force on Climate-related Financial Disclosures frameworks, noted the progress of our key ESG priorities and detailed our goals to reduce GHG emissions in support of an economy-wide transition to a net-zero world. We are working to reduce Scope 1 GHG and methane emissions by implementing ambitious targets and eliminating routine flaring, among other initiatives. In February 2022, we joined the Oil & Gas Methane Partnership ("OGMP") 2.0 Initiative to enhance reporting of methane emissions. Our inaugural OGMP 2.0 submission was rated the highest-level, "Gold Standard."We also established an ESG Advisory Council to advise management and our Board on ESG-related issues.

We use a variety of financial and operational metrics to assess the performance of our oil, natural gas and NGL operations, including:

Our development program is designed to prioritize the generation of attractive risk-adjusted returns and meaningful free cash flow and is inherently flexible, with the ability to modify our capital program as necessary to react to the current market environment.

We expect to incur approximately $575 million to $650 million, excluding acquisitions, for our 2023 capital program. The majority of our program is allocated to D&C, which approximately 85% is allocated to our operated assets primarily in the Eagle Ford and Uinta basins. We expect to fund our 2023 capital program through cash flow from operations. Due to the flexible nature of our capital program and the fact that majority of our acreage is held by production, we could choose to defer a portion or all of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil, gas and NGLs and resulting well economics, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners.

Our revenues are primarily derived from the sale of our oil, natural gas and NGL production and are influenced by production volumes and realized prices, excluding the effect of our commodity derivative contracts. Pricing of commodities are subject to

supply and demand as well as seasonal, political and other conditions that we generally cannot control. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. The following table illustrates our production revenue mix for each of the periods presented:

In addition, revenue from our midstream assets is supported by commercial agreements that have established minimum volume commitments. These midstream revenues comprise the majority of our midstream and other revenue. Midstream and other revenue accounts for 6% or less of our total revenues for each of the years ended December 31, 2022, 2021 and 2020.

The following table presents historical sales volumes for our properties:

Total sales volume increased 16,142 MBoe during the year ended December 31, 2022 compared to 2021. The increase is primarily due to the Merger Transactions, DJ Basin Acquisition and Central Basin Platform Acquisition (collectively, the "2021 Acquisitions") and our Uinta Transaction, which contributed an additional 10,777 MBoe and 7,740 MBoe, respectively. Sales volumes from our other assets decreased by 2,375 during the year ended December 31, 2022 compared to 2021, primarily as a result of the natural decline from our existing asset base, partially offset by new operated Eagle Ford well completions in 2022.

Our results of operations depend upon many factors, particularly the price of commodities and our ability to market our production effectively.

The oil and natural gas industry is cyclical and commodity prices can be highly volatile. In recent years, commodity prices have been subject to significant fluctuations. The outbreak of the COVID-19 virus followed by certain actions taken by OPEC caused crude oil prices to decline significantly beginning in the first half of 2020 and prices remained below pre-pandemic levels for a prolonged period of time, finally recovering to pre-pandemic levels during 2021 and into 2022. Commodity prices were higher in 2022, compared to 2021, reflecting the ongoing recovery in the oil and gas industry in 2022 due to increasing demand as more states and countries re-open and national and global economies recover from the global COVID-19 pandemic and a premium due to the reduction in crude oil supply resulting from sanctions imposed on Russia in response to its large-scale invasion of Ukraine in February 2022. Although commodity prices have increased substantially in 2022, uncertainty persists regarding OPEC’s actions, increased U.S. drilling, the continued effect from the COVID-19 pandemic, inflation and the armed conflict in Ukraine.

In order to reduce the impact of fluctuations in oil and natural gas prices on revenues, we regularly enter into derivative contracts with respect to a portion of the estimated oil, natural gas and NGL production through various transactions that fix the future prices received. We plan to continue the practice of entering into economic hedging arrangements to reduce near-term exposure to commodity prices, protect cash flow and corporate returns and maintain our liquidity.

The following table presents the percentages of our production that was economically hedged through the use of derivative contracts:

The following table sets forth the average NYMEX oil and natural gas prices and our average realized prices for the periods presented: