CRGY 10-K & 10-Q changes, risk factors and insider trading

•political and economic conditions, such as the conflicts in UkraineUkraine, Venezuela and the Middle East, in or affecting other producing regions or countries, including the Middle East, Africa, South America and Russia;

•actions of OPEC, including the ability and willingness of the members of OPEC and other exporting nations to agree to and maintain oil price and production controls, including the anticipated increases in supply from Russia and OPEC, particularly Saudi Arabia and Venezuela;

We have consolidated our business over time through acquisitions, including the UintaRidgemar Transaction, the Western Eagle Ford AcquisitionsAcquisition and the SilverBowVital MergerEnergy Merger, and there are risks associated with integration of all of these assets, operations and our ability to manage those risks. In addition, we may be unable to make attractive acquisitions or successfully integrate acquired businesses, assets or properties, and any inability to do so may disrupt our business and hinder our ability to grow.

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, in March 2022,2025, we acquired certain exploration and production assets in the state of Utah pursuant to the Uinta Transaction. In 2023 and 2024, we also acquired certain exploration and production assets in the state of Texas pursuant to the WesternRidgemar Eagle Ford AcquisitionsAcquisition and the SilverBowVital Energy Merger. 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 WesternRidgemar Eagle Ford AcquisitionsAcquisition and the SilverBowVital Energy Merger, 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 Permian and 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.

The unavailability or high cost of equipment, supplies, personnel and oilfield services, due to, among other things, potential tariffs, commodity price volatility or supply constraints as a result of the conflicts in UkraineUkraine, Venezuela and the Middle East, elevated, interest rates and associated policies of the Federal Reserve or otherwise could adversely affect our ability to execute development and exploitation plans on a timely basis and within budget, and consequently could materially and adversely affect our anticipated cash flow.

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 potential tariffs, the conflicts in UkraineUkraine, Venezuela and the Middle 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.

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

We contract with third-party service providers to support our operations. These contracted services are generally provided pursuant to master services agreements entered into between the third-party service providers and our operating subsidiaries. Although we have our own employees, our ability to conduct operations and generate revenues is dependent on the availability and performance of those third-party service providers and their compliance with the terms of their respective master service agreements (as further described under "Part III., Item 13. Certain Relationships and Related Party TransactionsTransactions, and Director Independence—KKR Funds"). We cannot guarantee that we will be successful in either retaining the services of our current third-party service providers or contracting with alternative service providers in the event that our current contractors discontinue providing services to us or fail to meet their obligations under their respective master services agreements. Any failure to retain the services of our current service providers or locate alternatives will negatively affect our ability to generate revenues and continue and expand our operations. Please see "Part I., Items 1 and 2. Business and Properties—Employees" for more information.

The U.S. inflation rate remained relatively stable through 2024 and 2025, after an extended period of rising rates, which began increasing in 2021 and remained elevated throughout 2023.2022. These inflationary pressures resulted in additional increases to the costs of our oilfield goods, services and personnel, which in turn caused our capital expenditures and operating costs to rise. Sustained levels of high inflation during such period likewise caused the U.S. Federal Reserve and other central banks to increase interest rates multiple times during such period. Although the U.S. Federal Reserve reduced benchmark interest rates in 2024,2024 and 2025, and may continue to reduce rates in 2025,2026, to the extent such rates remain elevated above historic levels, we may continue to experience higher costs and may encounter further cost increases for our operations, including oilfield services, labor costs and equipment if our drilling activity increases.

Pursuant to our Management Agreement, the Manager provides us with our senior management team and provides certain other management services. However, in each case such resources are not fully dedicated to our assets and operations, and the allocation of such resources is generally within the Manager’s discretion. See "Part III., Item 13. Certain Relationships and Related Party TransactionsTransactions, and Director Independence—Management Agreement.” Accordingly, our success depends on the efforts, experience, diligence, skill and network of business contacts of the Manager’s personnel. We can offer no assurance that the Manager will continue to provide services to us or that we will continue to have access to the Manager’s personnel. The Management Agreement had an initial three-year term, was automatically renewed on December 7, 2024 for an additional three-year term ending December 7, 2027, and will have automatic three-year renewals thereafter. Upon the written notice to the Manager at least 180 days prior to the expiration of the initial term or any automatic renewal term, we may, without cause, decline to renew the Management Agreement upon the affirmative determination of at least two-thirds of its independent directors reasonably and in good faith, that (1) there has been unsatisfactory long-term performance by the Manager that is materially detrimental to us and our subsidiaries taken as a whole or (2) the fees payable to the Manager, in the aggregate, are materially unfair and excessive compared to those that would be charged by a comparable asset manager managing assets comparable to our assets, subject to Manager’s right to renegotiate the fees. If the Management Agreement is terminated and no suitable replacement is found to provide management and operating services for our oil and natural gas assets, we may not be able to execute our business plan, and our financial condition and results of operation may be materially and adversely affected.

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

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

The disposal of fluids gathered from oil and natural gas producing operations in underground disposal wells has been pointed to by some groups and regulators as a potential cause of increased induced seismic events in certain areas of the country, particularly in Oklahoma, Texas, Colorado, Kansas, New Mexico and Arkansas. Several states have adopted or are considering adopting laws and regulations that may restrict or otherwise prohibit oilfield fluid disposal in certain areas or underground disposal wells, and state agencies implementing those requirements may issue orders directing certain wells in areas where seismic incidents have occurred to restrict or suspend disposal well operations or impose standards related to disposal well construction and monitoring. For example, in December 2021 the TRC issuedhas asuspended noticeproduced towater suspendhandling thepermits permitand ofintroduced allinjection deepvolume disposal wellscurtailments within the Northernboundaries Culberson-Reevesof certain Seismic Response Area.Areas. Similarly, in Oklahoma, the Oklahoma Corporation Commission has at times limited drilling or ordered wells to be shut down in response to seismic activity. In November 2021, New Mexico implemented protocols requiring operators to take various actions within a specified proximity of certain seismic activity, including a requirement to limit injection rates if a seismic event is of a certain magnitude. Further, in July 2024, the New Mexico Office Conservation District announced the administrative cancellation of 75 pending permit applications for UIC Class II wells within the 10-mile County Line Seismic Response Area, due to the potential for increased seismicity within the area. While we cannot predict the ultimate outcome of these actions, any action that temporarily or permanently restricts the availability of disposal capacity for produced water or other oilfield fluids may increase our costs or have other adverse impacts on our operations.

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

In addition, the pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the DOT through PHMSA. PHMSA has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. These standards may be revised by PHMSA over time. For example, in October 2019, PHMSA published three final rules that create or expand reporting, inspection, maintenance, and other pipeline safety obligations. As part of the Consolidated Appropriations Act of 2021, the U.S. Congress reauthorized PHMSA through 2023 and directed the agency to move forward with several regulatory actions, including but not limited to the issuance of final regulations to require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations. PHMSA has issued various rules to address certain of these requirements. For example, in January 2025, PHMSA finalized a rule to address the management of methane emissions through more stringent leak detection and repair requirements, among other matters. However, PHMSA subsequently withdrew this rule before publication pursuant to the Trump Administration's positionJanuary on20, such2025, rulingregulatory is currently unknownfreeze, and wePHMSA cannothas predictyet anyto reactionpublish a revised version of the Trump Administration with respect to such ruling.rule. Notwithstanding this, PHMSA ismay be continuing to work on developing additional regulations related to safety oversight of gas gathering pipelines, and additional future regulatory action expanding PHMSA’s jurisdiction and imposing stricter integrity management requirements is possible. The adoption of laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operating costs that could be significant. In addition, should we fail to comply with PHMSA or comparable state regulations, we could be subject to substantial fines and penalties. As of December 28,30, 2023,2024, the maximum civil penalties PHMSA can impose are $266,015$272,926 per violation per day, with a maximum of $2,660,135$2,729,245 for a related series of violations.

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

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

Additionally,However, 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 October 2024, the Colorado Energy and Carbon Management Commission finalized rules that 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 rules 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.

Governmental,Litigation scientific,risks and public concern overregarding the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States and has included various climate change related pledges and actions. For example, in January 2024, the Biden Administration temporarily paused pending decisions on new exports of LNG to countries that the United States does not have free trade agreements with. However, upon taking office in January 2025, President Trump signed an Executive Order resuming the processing of permit applications for such projects. For more information, see our regulatory disclosure in “Items 1 and 2. Business and Properties.” Litigation risks are also increasing, as a number of parties have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts. There have also recently been certain increasing financial risks for fossil fuel producers as certain shareholders currently invested in fossil-fuel energy companies concerned about potential effects of climate change 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, although this trend has waned recently and several high-profile banks and institutional investors have withdrawn from various associations that aim to limit financing of industries that emit significant GHG emissions. 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, in March 2024, the SEC released a final rule requiring climate-related disclosures from registrants, including data on Scope 1 and 2 GHG emissions as well as any set climate-related targets and goals. However, the future of the rule is uncertain at this time given that its implementation has been stayed pending the outcome of legal challenges; moreover, it is uncertain whether, under the new Trump Administration, the SEC will change or revoke the rule, and we cannot predict whether such action will occur or its timing. If the final rules are implemented as currently written, we also cannot predict how such disclosures may be considered by financial institutions and investors when making investments decisions, and it is possible that we could face increased costs or restrictions on our access to capital.

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

In March 2024, the BLM finalized a rule that requires operators to limit flaring from well sites on federal lands, as well as allow the delay or denial of permits if BLM finds that an operator's methane waste minimization plan is insufficient. Litigation challenging the rule is currently being held in abeyance while the Trump Administration considers revisions to the rule and, in December 2025, the BLM announced it would delay enforcement of the impending regulatory compliance deadlines under that rule. In addition, the BLM finalized a rule in April 2024 updating the fiscal terms of oil and gas leases on federal lands and the criteria BLM considers when determining whether to lease nominated land. For more information, see our regulatory disclosure in "Items 1 and 2. Business and Properties—Legislative and regulatory environment—Hydraulic fracturing."

In addition, some states, including Texas, have adopted, and other states are considering adopting, regulations that restrict or could restrict hydraulic fracturing in certain circumstances and that require the disclosure of the chemicals used in hydraulic fracturing operations. Further, state and local governmental entities have exercised the regulatory powers to regulate, curtail or in some cases prohibit hydraulic fracturing. For example, Colorado has adopted more stringent setbacks for oil and gas development and, in October 2024, adopted final rules that would apply increased scrutiny to the cumulative impacts of GHG emissions of oil and gas development and set GHG emissions targets for oil and gas operators. In California, Senate Bill No. 1137 was signed into law onin September 16, 2022, which establishesestablishing 3,200 feet as the minimum distance between new oil and gas production wells and certain sensitive receptors such as home, schools or parks effective January 1, 2023.2023, However,although oncertain Februarycompliance 3,deadlines 2023,have been delayed due to the Secretarysigning 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. In June 2024, the ballot proposal was withdrawn with the proposal’s sponsors instead indicating a view to challenging Senate Bill No. 1137 in court. The provisions of Senate Bill No. 1137 became effective immediately in June 2024. In September 2024, the Governor of California signed into law Assembly Bill 218,218 whichin delaysSeptember the deadline for some compliance with applicable regulations implementing Senate Bill No. 1137 until July 1, 2026, and further delays compliance with certain other requirements of Senate Bill No. 1137 by up to three years.2024. New laws or regulations that impose new obligations on, or significantly restrict hydraulic fracturing, could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect our determination of whether a well is commercially viable and increase our cost of doing business. Such increased costs and any delays or curtailments in our production activities could have a material and adverse effect on our business, prospects, financial condition, results of operations and liquidity.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, such as those restrictions imposed under the federal ESA and MBTA. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist, such as the dunes sagebrush lizard, lesser prairie chicken, and greater sage grouse, and where other species that potentially could be listed as threatened or endangered under the ESA may exist. In May 2024, the FWS issued a final rule listing the dunes sagebrush lizard as endangered under the ESAESA, and,although this decision has been challenged. For more information, see our regulatory disclosure in November"Items 2022, the FWS listed two distinct population segments of the lesser prairie-chicken under the ESA. Additionally, the Biden Administration took action to broaden enforcement under the ESA, including expanding the definition of “critical habitat.” The designation of previously unprotected species in areas where we operate as threatened or endangered, a recategorization of a species from threatened to endangered, or an expansion of areas designated as “critical habitat” could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration, development1 and production2. activities that could have an adverse impact on our ability to developBusiness and produce our reserves. To the extent species are listed or critical habitats are designated under the ESA or similar laws, or previously unprotected species are designated as threatened or endangered in areas where our properties are located, operations on those properties could incur increased costs arising from species protection measuresProperties—Legislative and faceregulatory delaysenvironment—Endangered orSpecies limitationsAct withand respectMigratory toBird productionTreaty activities thereon.Act."

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

Moreover, while we may create and publish voluntary or mandatory disclosures regarding sustainability-related matters from time to time, many of the statements in those voluntarysuch disclosures are based on expectations and assumptions andor hypothetical scenarios that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions or hypothetical scenarios are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established approach to identifying, measuring and reporting on many sustainability-related matters. We may also announce participation in, or certification under, various third-party sustainability or climate-related frameworks in an attempt to improve our sustainability profile, but such participation or certification may be costlycostly, may be reliant on unsettled methodologies, and may not achieve the desired results. Additionally, while we may announce various voluntary climate or sustainability-related targets, such targets are aspirational. We may not be able to meet or make progress against such targets in the manner or on such a timeline as initially contemplated, including but not limited to as a result of unforeseen costscosts, inaccurate forecast or technical difficulties associated with achieving such results.difficulties. To the extent we meet or make progress against such targets, it may be achieved through various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our environmental impact instead of actual changes in our environmental performance. However, we cannot guarantee that there will be sufficient offsets available for purchase given the demand from numerousthird businesses implementing net zero goals,parties, or that any offsets we do purchase will successfully achieve the emissions reductions they represent. Also, despite these aspirational goals and any other actions taken, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other sustainability-related goals, but we cannot guarantee that we will be able to pursue or implement such goals because of potential costs or technical or operational obstacles.

In addition, some organizations that provide information to investorsinvestors, ratings or proxy advisory services on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESGsustainability matters.concerns. Such ratings or recommendations are used by some investors to inform their investment and voting decisions. While such ratings or recommendations do not impact all investors’ investment or voting decisions, unfavorable ESGratings ratingsor recommendations and any recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our access to and costs of capital. Also, institutionalcertain lendersfinancial institutions may decide not to provide funding or insurance for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects. Additionally, to the extent sustainability-related matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations. sustainability-relatedSustainability-related matters may also impact our suppliers and customers, which may ultimately have adverse impacts on our operations.

Furthermore, certain public statements with respect to sustainability matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities, as well as other parties, related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential benefits. For example, thefederal SECand hasstate recentlyregulators have taken enforcement action against companies for ESG-relatedsuch misconduct,misconduct. including greenwashing. CertainSuch regulators, such as the SEC and various state agencies, as well as non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain ESG-statements,sustainability-related statements, goals or standards were misleading, false or otherwise deceptive. Certain employment practices and social initiatives are the subject of scrutiny by both those advocating for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and legal frameworks applicable to such initiatives continue to evolve. We cannot be certain of the impact of such regulatory, legal and other developments on our business. More recent political developments could mean that the Company faces increasing criticism or litigation risks from certain “anti-ESG” parties, including various governmental agencies. Such sentiment may focus on the Company’s environmental or social commitments (such as reducing GHG emissions) or its pursuit of certain employment practices or social initiatives that are alleged to be political or polarizing in nature or are alleged to violate laws based, in part, on changing priorities of, or interpretations by, federal agencies or state governments. Consideration of ESG-related factors in the Company’s decision-making could be subject to increasing scrutiny and objection from such anti-ESG parties. As a result, we may face increased litigation risk from private parties and governmental authorities related to our sustainability-related efforts. In addition, any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. In addition, certain institutions have also undertaken anti-ESG initiatives focused around their view of the politicization of ESG issues. We could face increasing costs as we attempt to comply with and navigate further regulatory sustainability-related focus and scrutiny.

We are partially dependent on our Revolving Credit Facility, our Crescent Minerals and Royalties Credit Facility and continued access to capital markets to successfully execute our operating strategies.

If we are unable to make capital expenditures or acquisitions because we are unable to obtain capital or financing on satisfactory terms, we may experience a decline in our oil and gas production rates and reserves. We are partially dependent on external capital sources to provide financing for certain projects. The availability and cost of these capital sources is cyclical, and these capital sources may not remain available, or we may not be able to obtain financing at a reasonable cost in the future. Elevated interest rates may increase the cost of capital and prevent us from being able to obtain debt financing at favorable rates, or at all, which would materially impact our operations. In addition, conditions in the global capital markets have been volatile due to among other things, the conflicts in UkraineUkraine, Venezuela and Israel, making terms for certain types of financing difficult to predict, and in certain cases, resulting in certain types of financing being unavailable. If our revenues decline as a result of lower oil, gas or NGL prices, operating difficulties, declines in production or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. Our failure to obtain additional financing could result in a curtailment of our operations or not make acquisitions, which in turn could lead to a possible reduction in our oil or gas production, reserves and revenues, not having sufficient liquidity to meet future financial obligations and could negatively impact our results of operations.

We have incurred significant additional indebtedness during recent periods.periods, including our issuance of senior unsecured notes and our assumption of Vital’s senior unsecured notes in connection with the Vital Energy Merger. Our additional indebtedness may impair our ability to raise further capital, including to expand our business, pursue strategic investments, and take advantage of financing or other opportunities that we believe to be in the best interests of the Company and our shareholders.

A reduction in the borrowing base under our Revolving Credit Facility and our Crescent Minerals and Royalties Credit Facility as a result of periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

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

The borrowings under our Revolving Credit Facility and our Crescent Minerals and Royalties Credit Facility expose us to interest rate risk.

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

Pursuant to the 2021 Registration Rights Agreement (as defined below) and the registration rights agreement entered into in connection with the Ridgemar Registration Rights Agreement,Acquisition, we have registered for resale all of the shares of our Class A Common Stock (including shares of Class A Common Stock to be issued upon redemption of a corresponding number of Class B Common Stock) held by the former owners of Independence and Ridgemar. The 2021 Registration Rights Agreement provides for additional demand and "piggyback" rights that would facilitate future sales of our Class A Common Stock in the public market. In addition to sales pursuant to such registration by selling stockholders, certain of our significant stockholders, including certain of Independence's former owners, have distributed shares of our securities that they hold to their investors who themselves may then sell into the public market. Any sales of such securities may depress the price of our shares. Furthermore, we filed registration statements with the SEC on Form S-8 providing for the registration of 6,520,410 shares of our Class A Common Stock issued or reserved for issuance under the Equity Incentive Plan. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144 under the Securities Act of 1933, as amended, shares registered under the registration statement on Form S-8 have been made available for resale immediately in the public market without restriction.

Our hedging contracts may result in substantial gains or losses. For example, we had realized commodity derivative lossesgains of $35.9$81.6 million in 2024,2025, and we may realize additional substantial future losses due to our hedging activities. In addition, if we enter into any hedging contracts and experience a sustained material interruption in our production, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity.

Our only principal asset is our interest in OpCo; accordingly,OpCo, which in turn holds interests in our operating subsidiaries; accordingly, we depend on distributions and other payments from OpCo and our operating subsidiaries, the amount of which will depend on various factors.subsidiaries.

We are a holding company and have no material assets other than our ownership interest in OpCo, which in turn holds interests in our operating subsidiaries. WeBecause we have no independent means of generating revenue or cash flow and we anticipate that the only source of our earnings will be cash distributions from our operating subsidiaries. Because we have no independent means of generating revenue,subsidiaries, our ability to make tax payments andpayments, payments under the Management Agreement and pay our other obligations, including corporate overhead expenses, is dependent on the ability of our operating subsidiaries to make distributions to OpCo and the ability of OpCo to make distributions to us in an amount sufficient to cover such obligations. This ability, in turn, depends on the ability of our operating subsidiaries to make distributions to OpCo.

The ability of OpCo, our operating subsidiaries and other entities in which OpCo directly or indirectly holds an equity interest to make such distributions will be subject to, among other things, (i) the applicable provisions of Delaware law (or other applicable jurisdiction) that may limit the amount of funds available for distribution and (ii) restrictions in relevant debt instruments of OpCo or its subsidiaries and other entities in which OpCo directly or indirectly holds an equity interest, including any restrictions on the payment of distributions required under the Revolving Credit Facility. InTo addition,the extent that we doneed notfunds whollyand ownOpCo certain of our operating subsidiaries. As a result, if such operating subsidiaries make distributions, including tax distributions, they will also have to make distributions to their noncontrolling interest owners. The amount of cash thator our operating subsidiaries canare distributerestricted eachfrom quartermaking such distributions or payments under applicable law or regulation or under the terms of any current or future indebtedness agreements, or are otherwise unable to theirprovide ownerssuch principallyfunds, dependsour upon the amount of cash they generate from their operations, which will fluctuate from quarter to quarter based on, among other things, the amount of oilliquidity and naturalfinancial gascondition our operating subsidiaries produce from existing wells; our operating subsidiaries’ ability to fund their drilling and development plans; the levels of investments in each of our operating subsidiaries, which maycould be limitedmaterially andadversely disparate; and prevailing economic conditions, including the supply of, or demand for, oil, natural gas and NGLs.affected.

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

If at any time we cease to be a controlled company, we will take all action necessary to comply with the Sarbanes-Oxley Act and NYSE rules, including ensuring that our Board of Directors has a majority of independent directors and ensuring that our Compensation Committee and Nominating & Governance Committee are each composed entirely of independent directors, subject to a permitted “phase-in” period.

Our Preferred Stockholder is the sole holder of our Non-Economic Series I Preferred Stock and is expected to retain its ownership of our Non-Economic Series I Preferred Stock until such time as it ceases to own more than 14,369,367 shares of Common Stock, subject to certain exceptions. Our Non-Economic Series I Preferred Stock entitles the holder thereof to appoint our entire Board of Directors and to certain other to approval rights with respect to certain fundamental corporate actions, including debt incurrence in excess of 10% of thenthe outstanding indebtedness, significant equity raises, preferred equity issuances, adoption of a shareholder rights plan, amendments of our certificateCertificate of incorporationIncorporation and certain sections of its bylaws, a sale of all or substantially all of our assets, mergers involving us, removals of our Chief Executive Officer and the liquidation or dissolution of us. Unlike common equity in traditional corporate structures, holders of our common stock will not vote for the election of directors. As a result, holders of our common stock will have less ability to influence our business than would the holders of common equity in a traditional corporate structure.

Management's Discussion and Analysis of Financial Condition and Results of Operations is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. The following discussion and analysis should be read in conjunction with the Consolidated Financial Statements and related Notes included in "Item 8. Financial Statements and Supplementary Data" of this Annual Report and also with "Part I., Item 1A. Risk Factors" of this Annual Report. The following information updates the discussion of our financial condition provided in our previous filings, and analyzes the changes in the results of operations between the years ended December 31, 20242025 and 2023.2024. Refer to our 20232024 Annual Report filed MarchFebruary 4,26, 20242025 for discussion and analysis of the changes in results of operations between the years ended December 31, 20232024 and 2022.2023. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward- looking statements. Factors that could cause or contribute to such differences include, but are not limited to, commodity price volatility, capital requirements and uncertainty of obtaining additional funding on terms acceptable to the Company, realized oil, natural gas and NGL prices, the timing and amount of future production of oil, natural gas and NGLs, shortages of equipment, supplies, services and qualified personnel, as well as those factors discussed below and elsewhere in this Annual Report , particularly under “Risk Factors” and “Cautionary Statement Regarding Forward Looking statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Crescent is a differentiated U.S. energy company committed to delivering value for shareholders through a disciplineddisciplined, returns-driven growth through acquisition strategy and consistent return of capital. Our long-life, balanced portfolio combines stablesignificant cash flowsflow from low-declinestable production with a deep, high-quality development inventory. Our activities are focused in Texasthe Eagle Ford, Permian and Uinta Basins, and we own minerals and royalty interests across premier U.S. oil and natural gas basins, primarily operated by large, well-capitalized companies, with a core focus in the RockyEagle Mountain region.Ford. Our Class A Common Stock trades on the NYSE under the symbol “CRGY.”

During the last several years, prices of crude oil, natural gas and NGLs have experienced periodic downturns and sustained volatility, impacted by thegeopolitical COVID-19events, pandemicsuch and recovery,as Russia’s invasion of Ukraine and the related sanctions imposed on Russia, Hamas' attack against Israel and the ensuing conflict and escalation of tensions in the Middle EastEast, (including the conflict with LebanonIran, andrecent Yemen),developments in Venezuela, supply chain constraints, elevated interest ratesrates, U.S. international trade and tariff policy developments and responses thereto and costs of capital and political and regulatory uncertainties, including any proposed tariffs.uncertainties. Furthermore, the United States has experienced, and may continue to experience, a significant inflationary environment, which began in 2022 that, along with international geopolitical risks,risks and market responses to the announcement of certain tariff policies by the Trump Administration, has contributed to concerns of a potential recession in the United States in 20252026 that has created further volatility. InFor December 2024,example, OPEC announced anthat extensionit ofis itsphasing productionout oil output cuts ofby approximatelyincreasing 2.2411,000 millionbarrels per day, each month from May to July 2025 and then increasing to 548,000 barrels per day throughin August 2025. While actual production significantly diverged from these announced targets, as several OPEC members were unable to meet the endplanned ofincreases Marchwhen 2025.others Thecontinued to overproduce, the actions of OPEC with respect to oil production levels and announcements of potential changes in such levels, including agreement on and compliance with production cuts,levels may result in further volatility in commodity prices and the oil and natural gas industry generally. Such volatility may lead to a more difficult investing and planning environment for us and our customers. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.

Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. The U.S. inflation rate began increasing in 2021, peaked in the middle of 2022 and began to gradually decline in the second half of 2022 and into 2023 and has remained relatively stable through 2024.2024 and 2025, after an extended period of elevation. 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. Tariffs announced in 2025 and any further tariffs may also increase our operating costs. Sustained levels of high inflation and certain other market pressures have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates in 2022,2022 continuing throughand 2023. TheAlthough the U.S. Federal Reserve made cuts to benchmark interest rates in 2024 and itin is currently anticipated that it will make additional cuts; however,2025, there is no guarantee that such additional cuts will occur. Although the financial health of the oil and gas industry has shown improvement as compared to prior periods, to the extent elevated interest rates and inflation remains,remain, we may experience further cost increases for our operations, including oilfield services, labor costs and equipment. 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 inflationinflation, any subsequent monetary policy changes, and a significant increase in inflation, to the extent we are unable to recover higher costs through higher oil and natural gas prices and revenues, would negatively impact our business, financial condition and results of operations. See Part I, Item 1A. Risk Factors—"Risks related to the oil and natural gas industry—Continuing or worsening inflationaryInflationary issues and associated changes in monetary policy previously have resulted in and such issues, as well as certain proposed tariffs, may in the future result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise."

In June 2024, we issued $750.0 million aggregate principal amount of 7.375% senior notes due 2033 (the "2033 Notes") at par (the "June 2024 Offering"). In September 2024, we issued an additional $250.0 million,million aggregate principal amount of 2033 Notes at 101.000% of par (the "September 2024 Offering," and together with the June 2024 Offering, the "2033 Notes Offerings"). The aggregate proceeds from the 2033 Notes Offerings were approximately $982.1 million, after adjusting for premiums, the initial purchasers' discount and offering expenses. We used the aggregate net proceeds from the 2033 Notes Offerings to finance the majority of the SilverBow Merger, including (i) fund the cash paid to the SilverBow stockholders and holders of SilverBow restricted stock units in connection with the SilverBow Merger, and (ii) repay and extinguish SilverBow's existing indebtedness that was outstanding at the completion of the SilverBow Merger for $1.2 billion, including extinguishment costs. In connection with the repayment of SilverBow's debt we incurred a Loss on the extinguishment of debt of $36.5 million, inclusive of make whole fees.

In March 2024, we issued $700.0 million aggregate principal amount of 7.625% senior notes due 2032 (the "2032 Notes") at par (the “"March 2024 Offering”"). In December 2024, we issued an additional $400.0 million, aggregate principal amount of 2032 Notes at 100.250% of par (the "December 2024 Offering,Offering", and together with the March 2024 Offering, the "2032 Notes Offerings"). The aggregate proceeds from the 2032 Notes Offering were approximately $1,080.7 million, after deducting the initial purchasers' discount and offering expenses. We used the net proceeds from the March 2024 Offering to finance the majority of the consideration of a cash tender offer of our 7.25% senior notes due 2026 (the "2026 Notes") and the redemption of any remaining 2026 Notes (collectively, the "Tender Offer and Redemption") (eachfollowing termsuch ascash definedtender below)offer of all of the aggregate principal amount of the 2026 Notes outstanding for $714.8 million after including extinguishment costs, as discussed further below.costs. We used the proceeds from the December 2024 Offering to repay the amounts outstanding under our Revolving Credit Facility.

On December 3, 2024, we entered into the Membership Interest Purchase Agreement (the “Ridgemar Acquisition Agreement”)Agreement, pursuant to which we acquired all of the outstanding equity interests in RidgemarRidgemar. (EagleOn Ford)January LLC31, (“Ridgemar”).2025, Inwe connectionacquired with the closingall of the Ridgemaroutstanding Acquisitionequity interests in theRidgemar firstfor quarter of 2025, we paid $819$807.2 million in cash and issued 5.5 million shares of our Class A Common Stock to former Ridgemar owners, before any customary post closing adjustments (the "Ridgemar.Acquisition").Stock. In addition, we agreed to pay up to $170.0 million in contingent earn-out consideration may be paid quarterly in fiscal years 2026 and 2027 based on theif quarterly NYMEX WTI priceprices of crude oil are above certain thresholds in fiscal years 2026 and 20272027. (collectively,We accounted for the "Ridgemar Consideration”).Acquisition as an asset acquisition. See NOTE 3 – Acquisitions and Divestitures for additional information.

On July 30, 2024, we consummated the SilverBow Merger. See “—NOTE 3 – Acquisitions and Divestitures. Immediately following the SilverBow Merger, Crescent Energy Company completed a series of internal transactions following which the assets of SilverBow Resources, Inc. ("SilverBow") and its subsidiary became held by subsidiaries of Crescent Energy Finance LLC. In connection with the SilverBow Merger, Crescent issued 51.6 million shares of Class A Common Stock and paid $382.4 million in cash to former SilverBow shareholders, including amounts payable in respect of outstanding SilverBow equity awards. In connection with the closing of the SilverBow Merger, we repaid all of SilverBow’s outstanding indebtedness. See NOTE 3 – Acquisitions and Divestitures for additional information.

In Octoberthe 2024,first quarter of 2026, in a series of transactions, we acquired froma unaffiliatedportfolio thirdof parties certain interests in oilmineral and gasroyalty properties, rights and related assetsinterests located in Atascosa,the Frio,Eagle LaFord Sallefrom andunrelated McMullen Counties, Texasthird-parties for an aggregate consideration of approximately $156.0$355.3 million, includingsubject certainto customary purchase price adjustments.

We are members of the Oil & Gas Methane Partnership 2.0 Initiative, or OGMP 2.0, and receivedin 2025, following consecutive years on OGMP 2.0 Gold Standard pathwaypathway, ratingswe inachieved 2022,the 2023OGMP and2.0 2024Gold Standard Reporting designation for our credible plan to more accurately measure our methane emissions. OGMP 2.0 is the United Nations Environment Programme's flagship oil and gas reporting and mitigation program and the leading industry standard for methane emissions reporting. We alsopreviously established a Sustainability Advisory Council, an outside council comprising leading exportsexperts across key sustainability topics, to advise management and our Board of Directors on sustainability-related issues. See additional materials on our website at www.crescentenergyco.com/sustainability. However, please note that the contents and other materials on our website in general, are not intended or deemed to be incorporated into this Annual Report by reference.

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

Total sales volume increased 19,10421,380 MBoe during the year ended December 31, 20242025 compared to 2023.the year ended December 31, 2024. The increase is primarily due to the SilverBow Merger and our Western Eagle Ford Acquisitions, which closed in the secondRidgemar half of 2023.Acquisition.

The oil and natural gas industry is cyclical and commodity prices can be highly volatile. In recent years, commodity prices have been subject to significant fluctuations, either as a result of the COVID-19geopolitical pandemicevents, such as the recent events in Venezuela and recovery,expected increase in Venezuelan crude being brought to market, Russia’s invasion of Ukraine and the associated sanctions imposed on Russia, the Israel-Hamas conflict and the broader conflict in the Middle East, actions taken by OPEC, sustained elevatedlevels of inflation and increased U.S. drilling activity or otherwise. Uncertainty persists regarding OPEC’s actions, increased U.S. drilling, proposed tariffs, inflation and the armed conflicts in Ukraine and the Middle East.East and ongoing hostilities in Venezuela. Additionally, market concern regarding the health of the global banking sector and any resultant recessionary effects contributed, among other factors, to increased volatility in the price for oil and natural gas.

(1)The realized price presented above does not include $83.1 million and $60.8 million received from the settlement of acquired oil, gas and NGL derivative contracts for the years ended December 31, 2025 and 2024, respectively. For the year ended December 31, 2024. For the years ended December 31, 2023 and 2022,2023, the realized price presented above does not include $61.5 million and $49.9 million paid for the settlement of acquired oil derivative contracts, respectively.contracts.

Oil revenue. Oil revenue increased $379.5$242.3 million, or 22%,11%, in 20242025 compared to 2023.2024. This increase was driven by a $407.9$583.0 million increase from higher sales volumes (1522 MBbl/d, or 22%27%), partially offset by lower realized oil prices that resulted in a decrease of $28.4$340.7 million (a decline of 1%13% per Bbl). The increase in sales volumes was primarily driven by the SilverBow Merger and our Western Eagle Ford Acquisitions, which closed in the secondRidgemar half of 2023.Acquisition. The decrease in realized oil prices was due to lower index prices, which wasprices partially offset by more favorable price realizations.differentials.

Natural gas revenue. Natural gas revenue decreasedincreased $21.2$323.7 million, or 6%,93%, in 20242025 compared to 2023.2024. This decreaseincrease was driven by lowerhigher realized natural gas prices that resulted in aan decreaseincrease of $170.6$221.0 million (aan declineincrease of 33%49% per Mcf), partially offset byand a $149.4$102.7 million increase from higher sales volumes (143148 MMcf/d, or 40%30%). The increase in sales volumes was primarily due to the SilverBow Merger and our Western Eagle Ford Acquisitions, which closed in the secondRidgemar half of 2023.Acquisition. The decreaseincrease in realized natural gas prices was due to lowerhigher indexbenchmark prices and associated realizations.prices.

NGL revenue. NGL revenue increased $124.1$73.6 million, or 64%,23%, in 20242025 compared to 2023.2024. This increase was driven by a $106.5$101.8 million increase from higher sales volumes (1312 MBbl/d, or 57%33%), andpartially higheroffset by lower realized NGL prices that resulted in ana increasedecrease of $17.6$28.2 million (ana increasedecline of 6%7% per Bbl). The increase in sales volumes was primarily driven by the SilverBow Merger and our Western Eagle Ford Acquisitions, which closed in the secondRidgemar half of 2023.Acquisition.

Midstream and other revenue. Midstream and other revenue increased $66.0$9.2 million, or 97%,7%, in 20242025 compared to 2023,2024, duedriven toprimarily by higher sulfur revenues, higher oil blending and marketing revenues in 2024.2025.

(i)Lease and asset operating expenses increased $50.1$135.8 million, or 9%,21%, in 20242025 compared to 2023.2024. Additionally, lease and asset operating expense per Boe decreased $2.09$0.50 per Boe from $10.67$8.58 per Boe to $8.58$8.08 per Boe. This $50.1$135.8 million increase was driven primarily by higher production from the SilverBow Merger and Westernthe EagleRidgemar Ford Acquisitions,Acquisition, which closed in the second half of 2023, partially offset by cost reduction measures on our other assets. The additional costs from our acquisitions was more than offset on a per Boe basis with the additional acquired volumes and cost reduction measures.measures on our legacy assets.

(ii)Gathering, transportationprocessing and marketingtransportation expense increased $77.8$96.0 million, or 33%, in 2024 compared to 2023. However, gathering, transportation31%, and marketingincreased expense per Boe decreased $0.06$0.05 per Boe from $4.31$4.25 per Boe to $4.25$4.30 per Boe. This increaseBoe in expense2025 compared to 2024. The increase was driven primarily by the SilverBow Merger and our Western Eagle Ford Acquisitions, which closed in the secondRidgemar half of 2023, but was more than offset by the additional volumes from these acquisitions.Acquisition.

(iii)Production and other taxes decreasedincreased $0.3$56.8 million, or 0%,35%, in 20242025 compared to 20232024 and decreasedincreased $0.78$0.10 per Boe, or 26%,5%, to $2.21$2.31 per Boe. This decreaseincrease was driven primarily by lowerhigher effective tax ratesoil and increasedgas gathering, transportation and marketing expense,revenues, which decreasedincreased the tax base upon which our production and other taxes are calculated.

(iv)Workover expense increased $1.9$14.2 million in 20242025 compared to 2023,2024, and decreased $0.25$0.04 per Boe from $1.07$0.82 per Boe to $0.82$0.78 per Boe. This absolute dollar increase was primarily causeddriven by the SilverBow Merger.Merger and the Ridgemar Acquisition.

(v)Midstream and other operating expense increased $70.3$6.8 million, or 177%,6%, in 20242025 compared to 2023,2024, primarily due to increased crude oil blending expense.and Themarketing additionalexpenses, crude oil blending expensewhich was more than offset by additional oil blending and marketing revenue included as part of our Midstream and other revenue.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased $273.7$217.4 million, or 41%,23%, in 20242025 compared to 2023,2024, driven primarily by increased production from the SilverBow Merger and ourthe WesternRidgemar Eagle Ford Acquisitions and an increased DD&A rate.Acquisition.

Impairment expense. During the years ended December 31, 20242025 and 2023,2024, we evaluated our Oiloil and natural gas properties and Investments in equity affiliates and determined that certain amounts were impaired. As a result of our evaluations, during the year ended December 31, 2025, we recorded impairment charges of $254.6 million, including an impairment of $233.7 million to write down the carrying value of associated oil and natural gas properties to the estimated transaction price less cost to sell, and $20.8 million related to office lease impairments as part of our restructuring costs. During the year ended December 31, 2024, we recorded an impairment expense of $161.5 million related to Oiloil and natural gas properties that were determined not to be recoverable. During the year ended December 31, 2023, we recorded an impairment expense of $153.5 million, including $149.6 million related to Oil and natural gas properties that were determined not to be recoverable and $3.9 million related to Investments in equity affiliates.

General and administrative expense. General and administrative expense ("G&A") increased $195.3$135.9 million, or 139%,40%, in 20242025 compared to 2023,2024, driven primarily by (i) higher recurring G&A due to the SilverBow Merger and the Ridgemar Acquisition; (ii) an increase in equity-based compensation expense of $110.5$55.6 million (20242025 and 20232024 include additional catch up expense of $121.8$146.5 million and $30.4$121.8 million, respectively, due to change in estimate), and (iiiii) $63.8$30.4 million higher transaction and nonrecurring related expenses primarily driven by the SilverBow Merger and (iii) higher recurring G&A, primarily driven by higher Manager Compensation expense. The increase in the Manager Compensation expense is due to an increase in public ownership of Class A Common Stock and a corresponding increase in ownership of OpCo as a result of (i) our equity issuances, and (ii) share redemptions for our Class A Common Stock.expenses.

Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs decreased by $22.2$117.9 million compared to 2023,2024, primary driven by a $29.4$118.1 million higher gain on sale of assets recognized in 2024, partially offset by $7.3 million in higher exploration expenses.2025.

Interest expense. In 2024,2025, we incurred interest expense of $216.3$298.4 million, as compared to $145.8$216.3 million in 2023,2024, a 48%38% increase. The increase was primarily driven by higher average debt balances driven by the SilverBow Merger and the WesternRidgemar Eagle Ford Acquisitions.Acquisition.

Loss on extinguishment of debt. In 2025, we incurred a loss on the extinguishment of debt of our 2028 Notes of $29.2 million related to $22.3 million premium for the Tender Offer and the 2028 Notes Redemption and $6.9 million related to the write-off of outstanding deferred finance costs related to the 2028 Notes. In 2024, we incurred a loss on the extinguishment of debt of $59.1 million composed of (i) $22.6 million related our 2026 Notes, of which $14.8 million is associated with the premium and interest paid for the Tender Offer and Redemption and $7.8 million is related to the write-off of related outstanding deferred finance costs and (ii) $36.5 million related to the make whole provision and premium associated with the repayment of SilverBow’s Second Lien Notes.

There are a number of risks that we believe are applicable to our business and the oil and gas industry in which we operate. These risks are described elsewhere in this report or our other filings with the SEC,Securities and Exchange Commission, including the section entitled “Item 1A. Risk Factors” beginning on page 32 in our Annual Report. If any of the risks and uncertainties described within our Annual Report, our other filings with the SECSecurities and Exchange Commission or elsewhere in this Quarterly Report actually occur, our business, financial condition or results of operations could be materially and adversely affected.

Management'sManagement’s Discussion and Analysis of Financial Condition and Results of Operations ("“MD&A"”) is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company'sCompany’s operating results. The following discussion and analysis should be read in conjunction with Management'sManagement’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2025 ("“Annual Report"”), our Quarterly Report on Form 10-Q for the period ended March 31, 2026, as well as our unaudited condensed consolidated financial statements for the three and six months ended MarchJune 31,30, 2026 and 2025. The following information updates the discussion of our financial condition provided in our previous filings, and analyzes the changes in the results of operations between the three and six months ended MarchJune 31,30, 2026 and 2025. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, commodity price volatility, capital requirements and uncertainty of obtaining additional funding on terms acceptable to the Company, realized oil, natural gas and NGL prices, the timing and amount of future production of oil, natural gas and NGLs, shortages of equipment, supplies, services and qualified personnel, as well as those factors discussed below and elsewhere in this Quarterly Report and in our Annual Report, particularly under “Risk Factors” and “Cautionary Statement Regarding Forward Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. Unless otherwise stated or the context otherwise indicates, all references to “we,” “us,” “our,” "“Crescent"” and the “Company” or similar expressions refer to Crescent Energy Company ("“CEC"”) and its subsidiaries.

During the last several years, prices of crude oil, natural gas and NGLs have experienced periodic downturns and sustained volatility, impacted by geopolitical events, such as Russia’s invasion of Ukraine and the related sanctions imposed on Russia, Hamas'Hamas’ attack against Israel and the ensuing conflict and escalation of tensions in the Middle East. For example, the ongoing military conflict inwith Iran, which began in February 2026, has heightened geopolitical risk in key global energy markets and contributed to increased volatility in oil and gas commodity prices. The conflict has resulted in disruptions and constraints on maritime transit, supply chains, and energy infrastructure in the Middle East, including in and around the Strait of Hormuz, a critical choke point for global oil and liquefied natural gas shipments. These developments have led to elevated risk premiums in energy commodity prices and greater short‑term price uncertainty, causing global crude oil prices to surpass $100 per Bbl.Bbl at times. Commodity prices and broader market conditions have also been affected by developments in Venezuela, supply chain constraints, elevated interest rates, U.S. international trade and tariff policies and responses thereto and costs of capital and political and regulatory uncertainties. Furthermore, the United States has experienced, and may continue to experience, a significant inflationary environment, which began in 2022 that, along with international geopolitical risks and market responses to the announcement of certain tariff policies by the Trump Administration, has contributed to concerns of a potential recession in the United States in 2026 that has created further volatility. For example, actions taken by OPEC and allies+ with respect to production levels, and announcements of potential changes in such levels, including production adjustments during 2025 and the first quarterhalf of 2026, and changes in participation by member countries have contributed, and may continue to contribute, to volatility in commodity prices and in the oil and natural gas industry generally. Such volatility may lead to a more difficult investing and planning environment for us and our customers. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.

DuringThere were no impairment charges recognized during the three and six months ended MarchJune 31,30, 2026, no impairment expense was incurred.2026. During the three and six months ended MarchJune 31,30, 2025, we recorded an impairment expense of $45.6$3.0 million and $48.6 million, respectively, to write down the value of certain assets classified as held for sale to expected net proceeds. A decline of future commodity prices or a decrease in estimates of oil and natural gas reserves for our assets would likely result in an impairment charge. The actual amount of impairment incurred, if any, for these properties will depend on a variety of factors including, but not limited to, subsequent forward price curve changes, weighted-average cost of capital, operating cost estimates and future capital expenditures estimates. An estimate of the sensitivity to changes in assumptions in our fair value calculations is not practicable, given the numerous assumptions (e.g. reserves, pace and timing of development plans, commodity prices, capital expenditures, operating costs, drilling and development costs, inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices would likely be partially offset by lower costs.

Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. The U.S. inflation rate remained relatively stable through 2024, 2025 and thus far through 2026, after an extended period of elevation; however, the full impact of recent geopolitical actions (including the conflict inwith Iran) on inflation cannot be fully determined at this time. 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. Recently announced tariffs and any further tariffs may also increase our operating costs. Although the U.S. Federal Reserve made cuts to benchmark interest rates in 2024 and 2025, the Federal Reserve’s Board of Governors has, so far in 2026, kept rates steady and indicated that near-term cuts are unlikely.steady. Although the financial health of the oil and gas industry has shown improvement as compared to prior periods, to the extent elevated interest rates and inflation remain, we may experience further cost increases for our operations, including oilfield services, labor costs and equipment. 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, any subsequent monetary policy changes (including as a result of recent changes to the composition of the Federal Reserve’s Board of Governors expected in 2026), and a significant increase in inflation, to the extent we are unable to recover higher costs through higher oil and natural gas prices and revenues, would negatively impact our business, financial condition and results of operations. See Part I,I. Item 1A. Risk Factors—"“Risks related to the oil and natural gas industry—Inflationary issues and associated changes in monetary policy previously have resulted in and such issues, as well as certain proposed tariffs, may in the future result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise"” in our Annual Report.

The 2031 Convertible Notes are the Company’s senior, unsecured obligations and are (i) equal in right of payment with CEC's,CEC’s, as the issuer of the 2031 Convertible Notes, senior unsecured indebtedness; (ii) senior in right of payment to the issuer’s indebtedness that is expressly subordinated to the 2031 Convertible Notes; and (iii) effectively subordinated to the issuer’s secured indebtedness, to the extent of the value of the collateral securing that indebtedness. The 2031 Convertible Notes are not guaranteed by any of the Company'sCompany’s subsidiaries, and the Company'sCompany’s subsidiaries do not have any obligations under the 2031 Convertible Notes. Because the 2031 Convertible Notes are not guaranteed by any of the Company'sCompany’s subsidiaries, the 2031 Convertible Notes are structurally subordinated to all indebtedness and other liabilities, including the Revolving Credit Facility, the CRF Credit Facility,Facility (as defined below), other series of our Senior Notes, trade payables and (to the extent the Company is not a holder thereof) preferred equity, if any, of the CompanyCompany’s subsidiaries.

At December 31, 2025, we had $298.2 million outstanding aggregate principal amount of 7.750% senior notes due 2029 (the "“2029 Notes"”). In March 2026, we repurchased $39.1 million of our outstanding 2029 Notes in open market transactions, at an average price of 101.014%. As a result of the repurchases, we incurred a loss on the extinguishment of debt of approximately $0.4 million. In July 2026, we elected to redeem all of the remaining 2029 Notes (the “2029 Notes Redemption”) at a redemption price equal to 100.000% of the outstanding principal amount, or $258.7 million, plus accrued and unpaid interest to, but excluding, the redemption date.

In December 2025, we consummated the Vital Energy Merger. Immediately following the Vital Energy Merger, the Company completed a series of internal transactions following which the assets of Vital and its subsidiary became held by subsidiaries of CrescentCEF Energy(as Financedefined LLC.below). In connection with the Vital Energy Merger, Crescent issued 73.3 million shares of Class A Common Stock and paid $3.7 million in cash to settle outstanding Vital equity awards. In connection with the closing of the Vital Energy Merger, we repaid outstanding borrowings of $890.0 million and terminated the Vital revolving credit facility. See Notes to condensed consolidated financial statements, NOTE 3 – Acquisitions and Divestitures included in Part I. Item 1. Financial Statements of this Quarterly Report for additional information.

On January 31, 2025, we acquired all of the outstanding equity interests in Ridgemar (Eagle Ford) LLC ("“Ridgemar"”) for $807.2 million in cash and 5.5 million shares of our Class A Common Stock (the "“Ridgemar Acquisition"”). We accounted for the Ridgemar Acquisition as an asset acquisition. In addition, up to $170.0 million in contingent earn-out consideration may be paid in fiscal years 2026 and 2027 if quarterly NYMEX WTI prices of crude oil are above certain thresholds in 2026 and 2027 (collectively, the "“Ridgemar Contingent Consideration”). WeSee accountedNotes forto thecondensed Ridgemarconsolidated Acquisitionfinancial as an asset acquisition. Seestatements, NOTE 3 – Acquisitions and Divestitures included in Part I. Item 1. Financial Statements of this Quarterly Report for additional information.

During the threesix months ended MarchJune 31,30, 2026, we sold additional non-core assets to unrelated third-party buyers for $1.2 million in aggregate net cash proceeds and recorded a loss of $2.9 million on the sale of such assets.million.

During the threesix months ended MarchJune 31,30, 2025, we sold non-core assets to unrelated third-party buyers for $6.9$11.1 million in aggregate net cash proceeds and recorded a gain of $1.9 million and $12.8 million on the sale of such assets offor $10.9the million.three and six months ended June 30, 2025, respectively.

As consideration for the services rendered pursuant to the Management Agreement and the Manager’s overhead, including compensation of members of its executive management team, the Manager is entitled to receive compensation from the Company equal to $78.5 million per annum ("“Manager Compensation"”), as of MarchJune 31,30, 2026, which is included in General and administrative expenses on our condensed consolidated statements of operations. As the Company'sCompany’s business and assets expand, Manager Compensation will increase by an amount equal to 1.5% per annum of the net proceeds from all future issuances of our primary equity securities by the Company (including in connection with acquisitions). See NOTE 3 – Acquisitions and Divestitures included in Part I. Item 1. Financial Statements of this Quarterly Report for more information.

Additionally, the Manager is entitled to receive Incentive Compensation under which the Manager is targeted to receive Class A Common Stock based on the achievement of certain performance-based measures. Initially, the Incentive Compensation consisted of five tranches, each of which featured a separate three-year performance period and relates to a target number of shares of Class A Common Stock equal to 2% of the outstanding Class A Common Stock as of the time such tranche is settled (each, a "“Target PSU"”). The first two tranches have vested and were fully expensed as of December 31, 2025. So long as the Manager continuously provides services to us until the end of the performance period applicable to a tranche, the Manager is entitled to settlement of such tranche with respect to a number of shares of Class A Common Stock ranging from 0% to 4.8% of the outstanding Class A Common Stock at the time each tranche is settled. Accordingly, as our Class A Common Stock share count increases, the number of equity-classified Manager PSU target shares of our Class A SharesCommon Stock granted under the Crescent Energy Company 2021 Manager Incentive Plan increases.

Our revenues are primarily derived from the sale of our oil, natural gas and NGL production and are influenced by production volumes and realized prices, excluding the effect of our commodity derivative contracts. PricingCommodity of commoditiesprices are subject to supply and demand as well as seasonal, political and other conditions that we generally cannot control. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. The following table illustrates our production revenue mix for each of the periods presented:

In addition, revenue from our midstream assets is supported by commercial agreements that have established minimum volume commitments. These midstream revenues, as well as revenue associated with crude oil blending, comprise the majority of our midstream and other revenue. Midstream and other revenue accounts for 4% or less of our total revenues for the three and six months ended MarchJune 31,30, 2026 and 2025.

Total consolidated sales volumes increased 7,4386,557 MBoe and increased 13,995 MBoe during the three and six months ended MarchJune 31,30, 2026, respectively, compared to the three and six months ended MarchJune 31,30, 2025. Our Working interest sales volumes increased 6,9885,915 MBoe,MBoe and increased 12,903 MBoe during the three and six months ended June 30, 2026, respectively, primarily due to the Vital Energy MergerMerger, andpartially offset by our 2025 divestitures. Our Minerals and royalties sales volumes increased 450642 MBoe and increased 1,092 MBoe during the three and six months ended June 30, 2026, respectively, due to our 2026 Minerals Acquisitions.

The oil and natural gas industry is cyclical and commodity prices can be highly volatile. In recent years, commodity prices have been subject to significant fluctuations, either as a result of the geopolitical events, such as the recent eventsdevelopments in Venezuela, and expected increase in Venezuelan crude being brought to market, Russia’s invasion of Ukraine and the associated sanctions imposed on Russia, the Israel-Hamas conflict and the broader conflict in the Middle East, including the conflict with Iran and the disruption of shipments of crude oil and liquefied natural gas through the Strait of Hormuz, actions taken by OPEC,OPEC+ and other major producing countries, sustained levels of inflation and increased U.S. drilling activity or otherwise. Uncertainty persists regarding OPEC’sOPEC+’s actions, changes in participation by member countries, increased U.S. drilling, proposed tariffs, inflation and the armed conflicts in Ukraine and the Middle East, including with IranIran, and the potential for related supply disruptions and ongoingimpacts hostilitieson inglobal Venezuela.energy markets. Additionally, marketrecessionary concern regarding the health of the global banking sectorconcerns and anybroader resultantmacroeconomic recessionary effectsconditions contributed, among other factors, to increased volatility in the price for oil and natural gas.

(1) The realized price presented above does not include $60.6$62.1 million or $122.6 million received from the settlement of acquired oil, gas and NGL derivative contracts for the three and six months ended MarchJune 31,30, 2026, respectively, and does not include $17.9$17.0 million or $34.9 million received from the settlement of acquired oil, gas and NGL derivative contracts for the three and six months ended MarchJune 31,30, 2025.2025, respectively.

Three Months Ended MarchJune 31,30, 2026 Compared to Three Months Ended MarchJune 31,30, 2025

Oil revenue. Oil revenue increased $273.7$624.3 million, or 44%,104%, in the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025. This was driven by a $231.4 million increase from higher sales volume (38 MBbls/d, or 37%), and higher realized oil prices that resulted in an increase of $42.3$446.2 million (an increase of 5%57% per Bbl) and a $178.1 million increase from higher sales volume (32 MBbls/d, or 30%). The increase in sales volumes was primarily driven by the Vital Energy Merger.Merger, partially offset by our 2025 divestitures. The increase in realized oil prices was due to higher index pricing and more favorable price differentials.

Natural gas revenue. Natural gas revenue decreased $29.1$125.2 million, or 16%,79%, in the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025. This was driven by lower natural gas prices that resulted in a decrease of $54.2$142.4 million (a decrease of 25%81% per Mcf), partially offset by a $25.1$17.2 million increase from higher sales volume (8871 MMcf/d, or 13%11%). The increase in sales volumes was primarily due to the Vital Energy Merger.Merger, partially offset by our 2025 divestitures. The decrease in realized natural gas prices was due to lower index pricing and a decrease in our price differentials due to the Vital Energy Merger and resulting differentials in the Permian Basin.

NGL revenue. NGL revenue increased $17.5$31.2 million, or 16%,32%, in the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025. This was driven primarily by a $68.7$58.4 million increase from higher sales volume (3028 MBbls/d, or 64%58%), partially offset by lower realized NGL prices that resulted in a decrease of $51.2$27.2 million (a decrease of 29%17% per Bbl). The increase in sales volumes was primarily driven by the Vital Energy Merger.Merger, partially offset by our 2025 divestitures.

Midstream and other revenue. Midstream and other revenue decreased $29.5$33.4 million, or 83%,87%, in the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025, driven primarily by our 2025 divestitures.

Operating expense. Operating expense increased $25.5$17.6 million, or 6%,5%, in the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025, driven primarily by the following factors:

(i)Lease and asset operating expense increased $42.2$26.7 million, or 22%,15%, in the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025, and decreased $0.63$0.75 per Boe, or 8%,10%, to $7.64$6.80 per Boe. This $42.2$26.7 million increase was driven primarily by higher production from the Vital Energy Merger, which was more than offset on a per Boe basis with the additional acquired volumes and 2025 divestitures.

(ii)Gathering, processing and transportation expense decreased $3.2$11.6 million, or 3%,11%, in the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025, and decreased $1.20$1.34 per Boe, or 26%,30%, to $3.33$3.10 per Boe. These per Boe decreases were driven primarily by the Vital Energy Merger and our 2025 divestitures.

(iii)Production and other taxes decreasedincreased $4.7$13.9 million, or 8%,25%, in the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025, and decreased $0.78$0.03 per Boe, or 30%,1%, to $1.82$2.27 per Boe. This net decreaseincrease was driven primarily by ourthe 2025additional divestituresproduction higher tax rates, partially offset byfrom the Vital Energy Merger.Merger and higher oil prices.

(iv)Workover expense increased $14.3$13.5 million, or 89%,70%, in the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025, and increased $0.30$0.27 per Boe, or 43%,33%, to $0.99$1.08 per Boe. This increase was primarily driven by the Vital Energy Merger.

(v)Midstream and other operating expense decreased $23.1$24.9 million, or 77%,86%, in the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025, primarily due to our 2025 divestitures.

Depreciation, depletion and amortization. In the three months ended MarchJune 31,30, 2026, depreciation, depletion and amortization increased $71.6$60.9 million, or 25%,21%, compared to the three months ended MarchJune 31,30, 2025, driven primarily by increased production from the Vital Energy Merger.

Impairment expense. During the three months ended MarchJune 31,30, 2025, we recorded an impairment of $45.6$3.0 million to write down the value of certain assets classified as held for sale to expected net proceeds. We did not haverecognize impairment expense during the three months ended MarchJune 31,30, 2026.

General and administrative expense. General and administrative expense increaseddecreased $6.0$63.1 million, or 11%,51%, for the three months ended MarchJune 31,30, 2026, compared to the three months ended MarchJune 31,30, 2025. The increasedecrease was driven by a decrease in equity-based compensation expense of $72.1 million (2026 and 2025 include an additional true-up expense of $0.4 million and $69.3 million due to changes in estimate) partially offset by (i) higher recurring General and administrative expense primarily due to an increase in Manager Compensation as a result of the Vital Energy Merger and (ii) $5.1$0.1 million higher transaction and nonrecurring related expenses offset by a decrease in equity-based compensation expense of $2.1 million, (2026 and 2025 includes additional expense of $2.1 million and $8.6 million due to changes in estimate).expenses.

Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs increaseddecreased by $20.0$16.9 million, compared to the three months ended MarchJune 31,30, 2025, primarily driven by $6.3$5.2 million higherlower exploration expense recognized during the three months ended MarchJune 31,30, 2026 and a $13.7$11.7 million change in the gain or loss onfrom the sale of assets.

Interest expense. In the three months ended MarchJune 31,30, 2026, we incurred interest expense of $104.6$99.8 million, as compared to $73.2$75.2 million in the three months ended MarchJune 31,30, 2025, a 43%33% increase. This increase was driven primarily by higher average debt balances fromas a result of the Vital Energy Merger.

Gain (loss) on derivatives. We have entered into derivative contracts to manage our exposure to commodity price risks that impact our revenues and have derivative gains and losses related to our contingent earn-out consideration. Our lossgain on derivatives during the three months ended MarchJune 31,30, 2026 changeddecreased by $615.6$16.7 million, from a comparable loss during 2025 primarily due to changes in commodity prices relative to our strike price.

Income tax benefit (expense). We are a corporation that is subject to U.S. federal and state income taxes on our allocable share of any taxable income from OpCo. OpCo is a partnership and is generally not subject to U.S. federal and certain state taxes. For the three months ended MarchJune 31,30, 2026 and 2025, we recognized income tax benefitexpense of $82.3$169.9 million and income tax expense of $2.6$41.1 million, respectively, for an effective tax rate of 16.4%25.6% and 30.7%,20.2%, respectively. Our effective tax rate for the three months ended MarchJune 31,30, 2026 was lowerhigher than the statutory rate primarily due to the permanent difference recognized in conjunction with the performance stock units granted to our Manager ("“Manager PSUs"”) that vested during the three months ended March 31, 2026. Our effective tax rate for the three months ended March 31, 2025 was higher due to temporary timing differences of certain deductions and a higher state tax rate due to the apportionment changes created by the Ridgemar Acquisition..