Crescent Energy Company ("we," "us," or the "Company") files annual, quarterly and current reports with the SEC. The SEC maintains an Internetinternet 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”)sustainability 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.

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, including restrictions due to elevated interest rates, 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.

“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.

“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, 20222023 and ending December 1, 2022,2023, 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.

“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-capitalizeddifferentiated U.S. independent energy company withcommitted to delivering value for shareholders through a disciplined growth through acquisition strategy and consistent return of capital. Our portfolio of low-decline, cash-flow oriented assets comprises both mid-cycle unconventional and conventional assets with a long reserve life and deep inventory of low-risk, high-return development locations in proven regions across the lower 48 states that generate substantial cash flow supported by a predictable baseEagle Ford and Uinta basins.

Our leadership is an experienced team 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 mindsetproven investment and deep operational expertise to pursueoperating expertise. For more than a cash flow-based investment mandatedecade, Crescent and its predecessors have executed on a consistent growth through acquisition strategy focused on operated working interests with an activecash flow, risk management strategy.and returns. 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, 2022.2023. 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:

Our asset base, which is primarily located in Texas and the Rockies, 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%45% of Adjusted EBITDAX since 2018.2019.

Our PDP reserves as of December 31, 20222023 have estimated average five-year and ten-year annual decline rates of approximately 13% and 10%12%, respectively, and an estimated 20232024 PDP decline rate of 22%19%, 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 BarnettRockies represent approximately 84%76% of our proved reserves as of December 31, 2022,2023, 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$5.3 billion as of December 31, 2022.2023. 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, 2022.2023.

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 ESGsustainability-related 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,sustainability, 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.Rockies. 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 1.2of 1.3 million net acres as of December 31, 2022, 1.02023, 1.1 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, 2022,2023, we owned mineral interests in 174175 thousand gross acres and an overriding royalty interest in 125126 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, 20222023 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, 20222023 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 engineersreserve leads at each of our operating subsidiaries, who are petroleum engineersreserve experts with an average of 1819 years of reservoir and operations experience per person. This process is overseen by our Director of Corporate Reserves, who has over 1617 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, 20222023 from Ryder Scott Company, L.P. has over 4425 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

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.

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 26.031.7 MMBoe during the year ended December 31, 20222023 primarily relate to PUD locations added as part of the Uinta Acquisition. Extensions and discoveries of 48.5 MMBoe primarily relate to extensions on ourWestern Eagle Ford asset.Acquisitions. Revisions of previous estimates during the year ended December 31, 20222023 were primarily due to increased expected future costs driven by inflationchanges in the drill plan largely attributed to the removal of 7 MMBoe of certain Permian basin PUD locations in Pecos County from our five-year development plan. As a result of Crescent’s recent acquisitions in both the Eagle Ford and a higher commodity price environment.the Uinta basins, we anticipate the go forward capital program will be largely focused in these two regions. Additionally, during the year ended December 31, 2022,2023, we spent $209.0$301.8 million to convert 17.620.6 MMBoe to proved developed reserves.

All of such PUD reserves are scheduled to be developed within five years from the date such locations were initially disclosed astheir booking date. The PUD reserves.reserves are spread across multiple assets in Texas, Utah and Wyoming. 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 aan uniform (i.e., 20% per year) conversion of PUD reserves. At December 31, 2022,2023, we estimate that our future development costs relating to the development of PUD reserves are $451 million in 2023, $389$494 million in 2024, and $382$530 million in 2025 $245and $548 million in 2026, and $181$148 million in 2027.2027 and $67 million in 2028. 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, 2023, 2022, 2021, and 2020.2021.

The following table sets forth information regarding our PDPproductive wells as of December 31, 2022:2023:

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2022.2023.

The following table sets forth the number of total net undeveloped acres as of December 31, 20222023 that will expire in 2023, 2024, 2025, 2026 and 20262027 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

As of December 31, 2022,2023, 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, 2022.2023.

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 4.48,938 MMBoe in 20232024 and 7.06,219 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 $15.6 million, $4.5 million and $5.8 million and $14.5 million (including the termination of a midstream contract) for the years ended December 31, 2023, 2022 2021 and 2020,2021, 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.

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 870904 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.

We foster an entrepreneurial culture where open communication is encouraged, the views of our employees are heard and the results of their efforts are recognized. We implement an inclusive and dynamic recruiting process that utilizes online recruiting platforms, referrals and professional recruiters. We foster the growth and professional development of our employees through the use of a robust performance review process, which includes the creation of performance development goals and plans to achieve those goals in order to help our employees reach their full potential.

We retain employees by offering competitive wages and generous benefits that are designed to meet the varied and evolving needs of a diverse workforce. We provide employees with the ability to participate in health and welfare plans, including medical, dental, life and short-term and long-term disability insurance plans. In response to the COVID–19 pandemic, we increased safety measures and protocols for those employees choosing to report to the office.

We are committed to supporting and giving back to the communities in which we operate and live. We recognize the link between local communities, the success of our employees and, ultimately, the success of our business.

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,

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 2023,2024, the maximum penalty increased to $1,496,035$1,544,521 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 hasWe own an interstate liquids pipeline through a consolidated subsidiary 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,ours, 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

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$1,450,040 (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$1,472,546 (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

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 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,December 2023, the EPA issued a proposedfinal rule that if finalized, would establishestablished OOOOb as a more stringent 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. OwnersUnder the final rule, owners or operators of affected emission units or processes wouldwill have two years to comply with specificprepare and submit their plans to impose methane emission controls on existing sources. The presumptive standards of performance that may includeunder the final rule are generally the same for both new and existing sources, including enhanced leak detectingdetection 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 proposalfinal rule 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, triggering certain investigation and repair requirements, 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,However, it is likely that these requirements will be subject to legal challenges. Failure to comply with these new methane rules may result in substantial fines and penalties for non-compliance, as well as injunctive relief. 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

Climate change continues to attract considerable public and scientific attention. As a result, our operations as well as the operations of our operatorsin which we have a working interest but are not the operator 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. Colorado has begun to increasingly regulate oil and gas operations with consideration towards GHG emissions and cumulative impacts. In January 2024, the Colorado Energy and Carbon Management Commission (formerly the Colorado Oil and Gas Conversation Commission) released draft rules that, if finalized as proposed, would require regulators to consider cumulative impacts of oil and gas operations in permitting decisions and increase scrutiny on the project’s proximity to other industrial sites, residential and school areas, “disproportionately impacted communities,” and “cumulatively impacted communities.” The draft rules would also set GHG emissions intensity targets for oil and gas operators and require regulators to consider such targets in their cumulative impacts analysis, as well as the potential to restrict operations during the summer in Ozone Nonattainment Areas.

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 JanuaryTaking place throughout 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

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

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. In July 2023, the BLM proposed a rule to update the fiscal terms of federal oil and gas leases, which would increase fees, rents, royalties, and bonding requirements. The rule would also add new criteria for BLM to consider when determining whether to lease nominated land, including the presence of important habitats or wetlands, the presence of historical properties or sacred sites, and recreational use of the land. BLM anticipates a final action on the proposal in Spring 2024. 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. However, Colorado has begun to increasingly regulate oil and gas operations generally with consideration towards GHG emissions and their cumulative impacts, including releasing draft rules in 2024 that would apply increased scrutiny to a project’s location within or within 2,000 feet of impacted communities and other developments. 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

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,remains pending, 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. In June 2023, a notice of proposed rulemaking was issued proposing to revise the 2019 final rule relating to listing and reclassification of species and designation of critical habitat, reinstating prior language within the rule.

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

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.

Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. Investors should read carefully the following factors as well as the cautionary statements referred to in "Cautionary Statement Regarding Forward-Looking Statements" herein. If any of the risks and uncertainties described below or elsewhere in this Annual Report actually occur, the Company's business, financial condition or results of operations could be materially adversely affected.

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 conflictconflicts in Ukraine, Israel and the Gaza Strip, 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 2023 and 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 conflictrespective conflicts between Russia and Ukraine hasand Israel and Hamas have 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 pandemicAny drop in commodity prices 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

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 in December 2021, and in March 2022, we acquired certain exploration and production assets in the state of Utah pursuant to the Uinta Transaction (as defined herein).Transaction. In 2023, we also acquired certain exploration and production assets in the state of Texas pursuant to the Western Eagle Ford Acquisitions. 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,Western Eagle Ford Acquisitions, 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$78.22 per Bbl of oil and $6.36$2.64 per MMBtu of natural gas as of December 31, 2022,2023, which, in the case of oil, are substantially higher than the five yearfive-year NYMEX forward curve range of $62.76$61.53 to $80.50$72.13 per Bbl of oil and, $3.80 to $5.30 per Mcfin the case of natural gas.gas, within the five-year NYMEX forward curve range of $2.30 to $4.71 per Mcf. 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

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$78.22 per Bbl of oil and $6.36$2.64 per MMBtu of natural gas as of December 31, 2022,2023, which, are substantiallyin the case of oil, is higher than five yearthe five-year NYMEX forward curve range of $62.76$61.53 to $80.50$72.13 per Bbl of oil and, $3.80 to $5.30 per Mcfin the case of natural gas.gas, within the five-year NYMEX forward curve range of $2.30 to $4.71 per Mcf. 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.

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 conflictconflicts in Ukraine and the COVID-19 pandemic, risingMiddle East, elevated 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 steadilybegan increasing sincein 2021 and intoremained elevated throughout 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 although the U.S. Federal Reserve has indicated its intention to continue to raiseit may reduce benchmark interest rates throughout the remainder of 2023 in an effort2024, 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 such rates remain 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