Management’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’s operating results. The following discussion and analysis should be read in conjunction with Management’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 June 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 June 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. Business Crescent is a differentiated U.S. energy company committed to delivering value through a disciplined, returns-driven growth through acquisition strategy and consistent return of capital. Our long-life, balanced portfolio combines significant cash flow from stable production with deep, high-quality development inventory. Our activities are focused in the Eagle Ford, Permian Basin and Uinta Basin, 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 Eagle Ford. Geopolitical developments and economic environment 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’ attack against Israel and the ensuing conflict and escalation of tensions in the Middle East. For example, the ongoing military conflict with 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 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 that has created further volatility. For example, actions taken by OPEC+ with respect to production levels, and announcements of potential changes in such levels, including production adjustments during 2025 and the first half 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. There were no impairment charges recognized during the three and six months ended June 30, 2026. During the three and six months ended June 30, 2025, we recorded an impairment expense of $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, 33 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 with 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. 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), 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—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. Capital market transactions 2031 Convertible Notes In March 2026, we issued $690.0 million aggregate principal amount of 2.750% Convertible Senior Notes due 2031 (the “2031 Convertible Notes”) at par. The 2031 Convertible Notes bear interest at an annual rate of 2.750%, which is payable on March 15 and September 15 of each year, beginning on September 15, 2026, and mature on March 15, 2031, unless earlier converted or redeemed or purchased by the Company. The net proceeds of the 2031 Convertible Notes were approximately $671.0 million after deducting the initial purchasers’ discount and offering expenses. The net proceeds of the 2031 Convertible Notes were used in part to redeem all of our outstanding 2028 Notes (as defined below) as discussed below. Prior to December 15, 2030, the 2031 Convertible Notes are convertible only in certain circumstances and during specified periods. Thereafter, they are convertible at the noteholders’ election until shortly before the maturity date. Upon conversion, we may settle the conversions by paying or delivering, as applicable, in cash, shares of Class A Common Stock, or a combination thereof, at our election. The 2031 Convertible Notes have an initial conversion rate of 67.1456 shares of Class A Common Stock per each $1,000 principal amount, which represents an initial conversion price of approximately $14.89 per share of Class A Common Stock. In connection with the issuance of the 2031 Convertible Notes, we paid $56.6 million to enter into capped call transactions with certain financial institution counterparties designed to reduce potential dilution upon conversion of the 2031 Convertible Notes and/or offset cash payments in excess of the principal amount of the converted notes, in each case subject to the initial cap price of $22.48 per share of Class A Common Stock. The 2031 Convertible Notes are the Company’s senior, unsecured obligations and are (i) equal in right of payment with 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’s subsidiaries, and the Company’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’s subsidiaries, the 2031 Convertible Notes are structurally subordinated to all indebtedness and other liabilities, including the Revolving Credit Facility, the CRF Credit 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 Company’s subsidiaries. 34 2028 Notes At December 31, 2025, we had $500.0 million outstanding aggregate principal amount of 9.250% senior notes due 2028 (the “2028 Notes”). In March 2026, we elected to redeem all of the remaining 2028 Notes (the “2028 Notes Redemption”), at a price of 102.3125%. As a result of the 2028 Notes Redemption, we incurred a loss on the extinguishment of debt of approximately $17.0 million, including $5.4 million related to the non-cash write-off of outstanding deferred financing costs, discounts, and premiums. 2029 Notes 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. Acquisitions and divestitures Acquisitions Vital Energy Merger 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 CEF (as defined 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. Ridgemar Acquisition 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”). 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. Other Acquisitions Minerals Acquisitions In February 2026, we acquired a portfolio of mineral and royalty interests located in the Eagle Ford from unrelated third-parties for an aggregate consideration of approximately $309.9 million, including transaction costs and certain customary purchase price adjustments (the “February 2026 Minerals Acquisition”). In January 2026, we acquired a portfolio of mineral and royalty interests located in the Eagle Ford from unrelated third-parties for an aggregate consideration of approximately $47.9 million, including transaction costs and certain customary purchase price adjustments (the “January 2026 Minerals Acquisition” and together with the February 2026 Minerals Acquisition, the “2026 Minerals Acquisitions”). In July 2025, we acquired a portfolio of oil and natural gas mineral interests located in various U.S. oil and gas basins from an unrelated third-party for total cash consideration of approximately $67.9 million, including transaction costs and certain customary purchase price adjustments (collectively with the 2026 Minerals Acquisitions, the “Minerals Acquisitions”). 35 Webb Gas Acquisition In January 2025, we acquired additional interests in Crescent operated oil and gas properties located in Webb County, Texas from unaffiliated third parties for aggregate consideration of approximately $21.2 million, subject to customary post-closing adjustments. Divestitures During 2025, we sold non-core assets as part of our 2025 non-core asset divestiture program for total consideration in excess of $900.0 million. During the three and six months ended June 30, 2026, we received $11.5 million in additional net cash proceeds and recorded a gain of $13.6 million as part of the customary purchase price adjustments. During the six months ended June 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. During the six months ended June 30, 2025, we sold non-core assets to unrelated third-party buyers for $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 for the three and six months ended June 30, 2025, respectively. Stewardship We seek to improve the assets we own and acquire to deliver enhanced financial returns, operations and stewardship. We believe that being a responsible operator will produce better outcomes, creating a net benefit for society and the environment, while delivering attractive returns for our investors. We view exceptional sustainability performance as an opportunity to differentiate Crescent from its peers, mitigate risks and strengthen operational performance as well as benefit our stakeholders and the communities in which we operate. We are members of the Oil & Gas Methane Partnership 2.0 Initiative, or OGMP 2.0, and in 2025, following consecutive years on OGMP 2.0 Gold Standard pathway, we achieved the OGMP 2.0 Gold 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 previously established a Sustainability Advisory Council, an outside council comprising leading experts 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 by reference in this Quarterly Report. How we evaluate our operations We use a variety of financial and operational metrics to assess the performance of our oil, natural gas and NGL operations, including: •Production volumes sold, •Commodity prices and differentials, •Operating expenses, •Adjusted EBITDAX (non-GAAP), and •Levered Free Cash Flow (non-GAAP) Development program and capital budget Our development program, which consists of expenditures for drilling, completion and recompletion activities, and related facilities, is designed to prioritize the generation of attractive risk-adjusted returns and meaningful free cash flow and is inherently flexible, with the ability to modify our capital program as necessary to react to the current market environment. We expect to fund our 2026 capital program through cash flow from operations. Due to the flexible nature of our capital program and the fact that the majority of our acreage is held by production, we could choose to defer a portion or all of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling 36 activities, prevailing and anticipated prices for oil, natural gas and NGLs and resulting well economics, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Management Agreement Crescent Energy Company has a management agreement (the “Management Agreement”) with KKR Energy Assets Manager LLC (the “Manager”). Pursuant to the Management Agreement, the Manager provides the Company with members of its executive management team and certain management services. The Management Agreement has a term of three years, with automatic three-year renewals, unless the Company or the Manager elects not to renew the Management Agreement. The current term automatically renewed in December 2024 for an additional three-year term ending December 7, 2027 and will have automatic three-year renewals thereafter, unless the Company or the Manager elects not to renew the Management Agreement. 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 June 30, 2026, which is included in General and administrative expenses on our condensed consolidated statements of operations. As the Company’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. Prior to the Corporate Simplification, the Manager Compensation was reduced proportionally by the percentage of OpCo Units held as redeemable noncontrolling interests, with such amount distributed concurrently to the holders of redeemable noncontrolling interests. This cash distribution to the holders of redeemable noncontrolling interests did not represent additional Manager Compensation; rather, it represented an ordinary cash distribution to the holders of redeemable noncontrolling interests. In certain instances in our financial statements and other disclosures, we clarify the underlying event that requires us to make such distributions. 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 Common Stock granted under the Crescent Energy Company 2021 Manager Incentive Plan increases. Sources of revenues 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. Commodity prices 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: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Oil 89 % 71 % 83 % 68 % Natural gas 2 % 18 % 7 % 20 % NGLs 9 % 11 % 10 % 12 % 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 June 30, 2026 and 2025. 37 Production volumes sold The following table presents historical sales volumes for our properties: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Total consolidated Oil (MBbls) 12,699 9,801 25,281 18,962 Natural gas (MMcf) 65,022 58,572 131,882 117,526 NGLs (MBbls) 6,929 4,345 13,859 8,576 Total (MBoe) 30,465 23,908 61,120 47,125 Daily average (MBoe/d) 335 263 338 260 Working interest (CEF) Oil (MBbls) 12,142 9,604 24,359 18,570 Natural gas (MMcf) 62,307 56,997 126,431 114,469 NGLs (MBbls) 6,722 4,230 13,474 8,354 Total (MBoe) 29,249 23,334 58,905 46,002 Daily average (MBoe/d) 322 257 326 254 Minerals and royalties (CRF) Oil (MBbls) 557 197 922 392 Natural gas (MMcf) 2,715 1,575 5,451 3,057 NGLs (MBbls) 207 115 385 222 Total (MBoe) 1,216 574 2,215 1,123 Daily average (MBoe/d) 13 6 12 6 Total consolidated sales volumes increased 6,557 MBoe and increased 13,995 MBoe during the three and six months ended June 30, 2026, respectively, compared to the three and six months ended June 30, 2025. Our Working interest sales volumes increased 5,915 MBoe and increased 12,903 MBoe during the three and six months ended June 30, 2026, respectively, primarily due to the Vital Energy Merger, partially offset by our 2025 divestitures. Our Minerals and royalties sales volumes increased 642 MBoe and increased 1,092 MBoe during the three and six months ended June 30, 2026, respectively, due to our 2026 Minerals Acquisitions. Commodity prices and differentials Our results of operations depend upon many factors, particularly the price of commodities and our ability to market our production effectively. The oil and natural gas industry is cyclical and commodity prices can be highly volatile. In recent years, commodity prices have been subject to significant fluctuations, either as a result of geopolitical events, such as developments in Venezuela, 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+ and other major producing countries, sustained levels of inflation and increased U.S. drilling activity or otherwise. Uncertainty persists regarding OPEC+’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 Iran, and the potential for related supply disruptions and impacts on global energy markets. Additionally, recessionary concerns and broader macroeconomic conditions contributed, among other factors, to increased volatility in the price for oil and natural gas. In order to reduce the impact of fluctuations in oil and natural gas prices on revenues, we regularly enter into derivative contracts with respect to a portion of the estimated oil, natural gas and NGL production through various transactions that fix the future prices received. We plan to continue the practice of entering into economic hedging arrangements to reduce near-term exposure to commodity prices, protect cash flow and corporate returns and maintain our liquidity. 38 The following table presents the percentages of our production that was economically hedged through the use of derivative contracts: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Oil 66 % 56 % 67 % 57 % Natural gas 52 % 59 % 54 % 58 % NGLs — % 8 % — % 8 % The following table sets forth the average NYMEX oil and natural gas prices and our average realized prices for the periods presented: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Oil (Bbl): Average NYMEX $ 92.79 $ 63.74 $ 82.36 $ 67.58 Realized price (excluding derivative settlements) 96.61 61.47 83.86 64.45 Realized price (including derivative settlements) (1) 73.33 64.27 68.56 65.67 Natural Gas (Mcf): Average NYMEX $ 2.90 $ 3.44 $ 3.97 $ 3.55 Realized price (excluding derivative settlements) 0.52 2.71 1.46 2.95 Realized price (including derivative settlements) (1) 1.74 2.60 1.99 2.84 NGLs (Bbl): Realized price (excluding derivative settlements) $ 18.67 $ 22.59 $ 18.36 $ 23.99 Realized price (including derivative settlements) (1) 18.67 22.48 18.36 23.78 (1) The realized price presented above does not include $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 June 30, 2026, respectively, and does not include $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 June 30, 2025, respectively. 39 Results of operations: Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025 Revenues The following table provides the components of our revenues, respective average realized prices and net sales volumes for the periods indicated: Three Months Ended June 30, 2026 2025 $ Change % Change Revenues (in thousands): Oil $ 1,226,826 $ 602,488 $ 624,338 104 % Natural gas 33,776 159,001 (125,225) (79) % Natural gas liquids 129,371 98,142 31,229 32 % Midstream and other 4,981 38,352 (33,371) (87) % Total revenues $ 1,394,954 $ 897,983 $ 496,971 55 % Average realized prices, before effects of derivative settlements: Oil ($/Bbl) $ 96.61 $ 61.47 $ 35.14 57 % Natural gas ($/Mcf) 0.52 2.71 (2.19) (81) % NGLs ($/Bbl) 18.67 22.59 (3.92) (17) % Total ($/Boe) 45.63 35.96 9.67 27 % Net sales volumes: Oil (MBbls) 12,699 9,801 2,898 30 % Natural gas (MMcf) 65,022 58,572 6,450 11 % NGLs (MBbls) 6,929 4,345 2,584 59 % Total (MBoe) 30,465 23,908 6,557 27 % Average daily net sales volumes: Oil (MBbls/d) 140 108 32 30 % Natural gas (MMcf/d) 715 644 71 11 % NGLs (MBbls/d) 76 48 28 58 % Total (MBoe/d) 335 263 72 27 % Oil revenue. Oil revenue increased $624.3 million, or 104%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025. This was driven by higher realized oil prices that resulted in an increase of $446.2 million (an increase of 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, 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 $125.2 million, or 79%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025. This was driven by lower natural gas prices that resulted in a decrease of $142.4 million (a decrease of 81% per Mcf), partially offset by a $17.2 million increase from higher sales volume (71 MMcf/d, or 11%). The increase in sales volumes was primarily due to the Vital Energy 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 $31.2 million, or 32%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025. This was driven primarily by a $58.4 million increase from higher sales volume (28 MBbls/d, or 58%), partially offset by lower realized NGL prices that resulted in a decrease of $27.2 million (a decrease of 17% per Bbl). The increase in sales volumes was primarily driven by the Vital Energy Merger, partially offset by our 2025 divestitures. 40 Midstream and other revenue. Midstream and other revenue decreased $33.4 million, or 87%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025, driven primarily by our 2025 divestitures. Expenses The following table summarizes our expenses for the periods indicated and includes a presentation on a per Boe basis, as we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis: Three Months Ended June 30, 2026 2025 $ Change % Change Expenses (in thousands): Operating expense $ 407,672 $ 390,031 $ 17,641 5 % Depreciation, depletion and amortization 358,004 297,056 60,948 21 % Impairment of oil and natural gas properties — 2,985 (2,985) NM* General and administrative expense 61,494 124,612 (63,118) (51) % Other operating costs (13,202) 3,664 (16,866) NM* Total expenses $ 813,968 $ 818,348 $ (4,380) (1) % Selected expenses per Boe: Operating expense $ 13.38 $ 16.31 $ (2.93) (18) % Depreciation, depletion and amortization 11.75 12.42 (0.67) (5) % * NM = Not meaningful. Operating expense. Operating expense increased $17.6 million, or 5%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025, driven primarily by the following factors: (i)Lease and asset operating expense increased $26.7 million, or 15%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025, and decreased $0.75 per Boe, or 10%, to $6.80 per Boe. This $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 $11.6 million, or 11%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025, and decreased $1.34 per Boe, or 30%, to $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 increased $13.9 million, or 25%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025, and decreased $0.03 per Boe, or 1%, to $2.27 per Boe. This increase was driven primarily by the additional production from the Vital Energy Merger and higher oil prices. (iv)Workover expense increased $13.5 million, or 70%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025, and increased $0.27 per Boe, or 33%, to $1.08 per Boe. This increase was primarily driven by the Vital Energy Merger. (v)Midstream and other operating expense decreased $24.9 million, or 86%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025, primarily due to our 2025 divestitures. Depreciation, depletion and amortization. In the three months ended June 30, 2026, depreciation, depletion and amortization increased $60.9 million, or 21%, compared to the three months ended June 30, 2025, driven primarily by increased production from the Vital Energy Merger. Impairment expense. During the three months ended June 30, 2025, we recorded an impairment of $3.0 million to write down the value of certain assets to expected net proceeds. We did not recognize impairment expense during the three months ended June 30, 2026. General and administrative expense. General and administrative expense decreased $63.1 million, or 51%, for the three months ended June 30, 2026, compared to the three months ended June 30, 2025. The decrease 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 41 an increase in Manager Compensation as a result of the Vital Energy Merger and (ii) $0.1 million higher transaction and nonrecurring related expenses. Three Months Ended June 30, 2026 2025 $ Change % Change General and administrative expense (in thousands): Recurring general and administrative expense $ 38,120 $ 29,275 $ 8,845 30 % Transaction and nonrecurring expenses 1,867 1,769 98 6 % Equity-based compensation 21,507 93,568 (72,061) (77) % Total general and administrative expense $ 61,494 $ 124,612 $ (63,118) (51) % General and administrative expense per Boe: Recurring general and administrative expense $ 1.25 $ 1.22 $ 0.03 2 % Transaction and nonrecurring expenses 0.06 0.07 (0.01) (14) % Equity-based compensation 0.71 3.91 (3.20) (82) % Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs decreased by $16.9 million, compared to the three months ended June 30, 2025, primarily driven by $5.2 million lower exploration expense recognized during the three months ended June 30, 2026 and a $11.7 million change in the gain or loss from the sale of assets. Interest expense. In the three months ended June 30, 2026, we incurred interest expense of $99.8 million, as compared to $75.2 million in the three months ended June 30, 2025, a 33% increase. This increase was driven primarily by higher average debt balances as 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 gain on derivatives during the three months ended June 30, 2026 decreased by $16.7 million, 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 June 30, 2026 and 2025, we recognized income tax expense of $169.9 million and income tax expense of $41.1 million, respectively, for an effective tax rate of 25.6% and 20.2%, respectively. Our effective tax rate for the three months ended June 30, 2026 was higher than the statutory rate primarily due to the permanent difference recognized in conjunction with the performance stock units granted to our Manager (“Manager PSUs”). Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP) Adjusted EBITDAX and Levered Free Cash Flow are supplemental non-GAAP financial measures used by our management to assess our operating results and liquidity. See “—Non-GAAP financial measures” section below for their definitions and application. The following table presents a reconciliation of Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP) to net income (loss) and Levered Free Cash Flow (non-GAAP) to Net cash provided by operating activities, the most directly comparable financial measures, respectively, calculated in accordance with GAAP: 42 Three Months Ended June 30, 2026 2025 $ Change % Change (in thousands, except percentages) Net income (loss) $ 493,704 $ 162,498 $ 331,206 204 % Adjustments to reconcile to Adjusted EBITDAX: Interest expense 99,823 75,219 Income tax expense (benefit) 169,920 41,057 Depreciation, depletion and amortization 358,004 297,056 Exploration expense 366 5,574 Non-cash (gain) loss on derivatives (419,080) (178,592) Impairment expense — 2,985 Non-cash equity-based compensation expense 21,280 93,268 (Gain) loss on sale of assets (13,568) (1,910) Other (income) expense (471) (115) Transaction and nonrecurring expenses (1) 25,893 (193) Settlement of acquired derivative contracts 62,069 17,007 Adjusted EBITDAX (non-GAAP) $ 797,940 $ 513,854 $ 284,086 55 % Adjustments to reconcile to Levered Free Cash Flow: Interest expense, excluding non-cash amortization of deferred financing costs, discounts, and premiums (95,576) (71,430) Current income tax benefit (expense) (562) (6,673) Tax-related redeemable noncontrolling interest distributions made by OpCo — (165) Development of oil and natural gas properties (284,124) (264,711) Levered Free Cash Flow (non-GAAP) $ 417,678 $ 170,875 $ 246,803 144 % (1)Transaction and nonrecurring expenses of $25.9 million for the three months ended June 30, 2026 were primarily related to earn-out payments for the Ridgemar Acquisition, and divestiture and restructuring costs. Transaction and nonrecurring expense credits of $0.2 million for the three months ended June 30, 2025 were primarily related to proceeds from a legal settlement mostly offset by uncapitalized transaction costs related to the Ridgemar Acquisition and transaction costs related to our divestitures. Three Months Ended June 30, 2026 2025 $ Change % Change (in thousands, except percentages) Net cash provided by operating activities $ 706,788 $ 498,966 $ 207,822 42 % Changes in operating assets and liabilities (34,710) (73,544) Tax-related redeemable noncontrolling interest contributions (distributions) made by OpCo — (165) Transaction and nonrecurring expenses (1) 25,893 (193) Exploration expense 366 5,574 Other adjustments and operating activities 3,465 4,948 Development of oil and natural gas properties (284,124) (264,711) Levered Free Cash Flow (non-GAAP) $ 417,678 $ 170,875 $ 246,803 144 % (1)Transaction and nonrecurring expenses of $25.9 million for the three months ended June 30, 2026 were primarily related to earn-out payments for the Ridgemar Acquisition, and divestiture and restructuring costs. Transaction and nonrecurring expense credits of $0.2 million for the three months ended June 30, 2025 were primarily related to proceeds from a legal settlement mostly offset by uncapitalized transaction costs related to the Ridgemar Acquisition and transaction costs related to our divestitures. 43 Adjusted EBITDAX (non-GAAP) increased by $284.1 million, or 55%, in the three months ended June 30, 2026, compared to the three months ended June 30, 2025, primarily driven by additional production from the Vital Energy Merger and increased oil pricing. Levered Free Cash Flow (non-GAAP) increased by $246.8 million, or 144%, in the three months ended June 30, 2026 compared to the three months ended June 30, 2025, primarily driven by increased Adjusted EBITDAX, partially offset by $19.4 million of increased development of oil and natural gas properties expenditures and additional interest expense. Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025 Revenues The following table provides the components of our revenues, respective average realized prices and net sales volumes for the periods indicated: Six Months Ended June 30, 2026 2025 $ Change % Change Revenues (in thousands): Oil $ 2,120,146 $ 1,222,147 $ 897,999 73 % Natural gas 192,141 346,441 (154,300) (45) % Natural gas liquids 254,478 205,717 48,761 24 % Midstream and other 11,019 73,851 (62,832) (85) % Total revenues $ 2,577,784 $ 1,848,156 $ 729,628 39 % Average realized prices, before effects of derivative settlements: Oil ($/Bbl) $ 83.86 $ 64.45 $ 19.41 30 % Natural gas ($/Mcf) 1.46 2.95 (1.49) (51) % NGLs ($/Bbl) 18.36 23.99 (5.63) (23) % Total ($/Boe) 42.00 37.65 4.35 12 % Net sales volumes: Oil (MBbls) 25,281 18,962 6,319 33 % Natural gas (MMcf) 131,882 117,526 14,356 12 % NGLs (MBbls) 13,859 8,576 5,283 62 % Total (MBoe) 61,120 47,125 13,995 30 % Average daily net sales volumes: Oil (MBbls/d) 140 105 35 33 % Natural gas (MMcf/d) 729 649 80 12 % NGLs (MBbls/d) 77 47 30 64 % Total (MBoe/d) 338 260 78 30 % Oil revenue. Oil revenue increased $898.0 million, or 73%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025. This was driven by a $407.3 million increase from higher sales volume (35 MBbls/d, or 33%), and higher realized oil prices that resulted in an increase of $490.7 million (an increase of 30% per Bbl). The increase in sales volumes was primarily driven by the Vital Energy 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 $154.3 million, or 45%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025. The decrease was driven by lower natural gas prices that resulted in a decrease of $196.5 million (a decrease of 51% per Mcf), partially offset by a $42.2 million increase from higher sales volume (80 MMcf/d, or 12%). The increase in sales volumes was primarily due to the Vital Energy Merger, partially offset by our 2025 divestitures. The decrease in realized natural gas prices was due to a decrease in our price differentials due to the Vital Energy Merger and resulting differentials in the Permian Basin. 44 NGL revenue. NGL revenue increased $48.8 million, or 24%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025. This was driven primarily by a $126.8 million increase from higher sales volume (30 MBbls/d, or 64%), partially offset by lower realized NGL prices that resulted in a decrease of $78.0 million (a decrease of 23% per Bbl). The increase in sales volumes was primarily driven by the Vital Energy Merger, partially offset by our 2025 divestitures. Midstream and other revenue. Midstream and other revenue decreased $62.8 million, or 85%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025, driven primarily by our 2025 divestitures. Expenses The following table summarizes our expenses for the periods indicated and includes a presentation on a per Boe basis, as we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis: Six Months Ended June 30, 2026 2025 $ Change % Change Expenses (in thousands): Operating expense $ 836,688 $ 793,542 $ 43,146 5 % Depreciation, depletion and amortization 712,129 579,629 132,500 23 % Impairment of oil and natural gas properties — 48,632 (48,632) NM* General and administrative expense 124,294 181,382 (57,088) (31) % Other operating costs (3,805) (6,892) 3,087 NM* Total expenses $ 1,669,306 $ 1,596,293 $ 73,013 5 % Selected expenses per Boe: Operating expense $ 13.69 $ 16.84 $ (3.15) (19) % Depreciation, depletion and amortization 11.65 12.30 (0.65) (5) % * NM = Not meaningful. Operating expense. Operating expense increased $43.1 million, or 5%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025, driven primarily by the following factors: (i)Lease and asset operating expense increased $68.8 million, or 18%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025, and decreased $0.68 per Boe, or 9%, to $7.22 per Boe. This $68.8 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 our 2025 divestitures. (ii)Gathering, processing and transportation expense decreased $14.8 million, or 7%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025, and decreased $1.27 per Boe, or 28%, to $3.22 per Boe. The decrease was driven primarily by the Vital Energy Merger and our 2025 divestitures. (iii)Production and other taxes increased $9.2 million, or 8%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025, and decreased $0.41 per Boe, or 17%, to $2.04 per Boe. This increase was driven primarily by production from the Vital Energy Merger and higher oil prices, partially offset by our 2025 divestitures that were subject to higher production tax rates. (iv)Workover expense increased $27.9 million, or 79%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025, and increased $0.28 per Boe, or 37%, to $1.03 per Boe. This increase was primarily driven by the Vital Energy Merger. (v)Midstream and other operating expense decreased $47.9 million, or 81%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily due to our 2025 divestitures. Depreciation, depletion and amortization. In the six months ended June 30, 2026, depreciation, depletion and amortization increased $132.5 million, or 23%, compared to the six months ended June 30, 2025, driven primarily by increased production from the Vital Energy Merger. Impairment expense. During the six months ended June 30, 2025, we recorded an impairment of $48.6 million to write down the value of certain assets to expected net proceeds. We did not have impairment expense during the six months ended June 30, 2026. 45 General and administrative expense. General and administrative expense decreased $57.1 million, or 31%, for the six months ended June 30, 2026, compared to the six months ended June 30, 2025. The decrease was driven by a decrease in equity-based compensation expense of $74.2 million, (2026 and 2025 include an additional true-up expense of $2.4 million and $77.9 million, respectively, 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) $5.2 million higher transaction and nonrecurring related expenses. Six Months Ended June 30, 2026 2025 $ Change % Change General and administrative expense (in thousands): Recurring general and administrative expense $ 68,992 $ 57,087 $ 11,905 21 % Transaction and nonrecurring expenses 9,295 4,089 5,206 127 % Equity-based compensation 46,007 120,206 (74,199) (62) % Total general and administrative expense $ 124,294 $ 181,382 $ (57,088) (31) % General and administrative expense per Boe: Recurring general and administrative expense $ 1.13 $ 1.21 $ (0.08) (7) % Transaction and nonrecurring expenses 0.15 0.09 0.06 67 % Equity-based compensation 0.75 2.55 (1.80) (71) % Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs increased by $3.1 million, compared to the six months ended June 30, 2025, primarily driven by a $2.1 million lower gain on sale of assets and $1.0 million higher exploration expense recognized during the six months ended June 30, 2026. Interest expense. In the six months ended June 30, 2026, we incurred interest expense of $204.4 million, as compared to $148.4 million in the six months ended June 30, 2025. This increase was driven primarily by higher average debt balances as a result of the Vital Energy Merger. Loss on extinguishment of debt. During the six months ended June 30, 2026, we incurred a loss on extinguishment of debt of $17.4 million related to $12.0 million premium for the 2028 Notes Redemption and our repurchases of the 2029 Notes, and $5.4 million related to the non-cash write-off of outstanding deferred financing costs, discounts, and premiums. During the six months ended June 30, 2025, we did not incur a loss on the extinguishment of debt. 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 loss on derivatives during the six months ended June 30, 2026 changed by $632.3 million, from a comparable gain during the six months ended June 30, 2025 primarily due to changes in commodity prices relative to our strike prices. 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 six months ended June 30, 2026 and 2025, we recognized income tax expense of $87.6 million and income tax expense of $43.7 million, respectively, for an effective tax rate of 54.0% and 20.6%, respectively. Historically, our effective tax rate has typically been lower than the U.S. federal statutory income tax rate of 21% primarily due to effects of removing income and losses related to our noncontrolling interests and redeemable noncontrolling interests. However, as part of our Corporate Simplification, we expect our effective rate to be more in line with the U.S. federal statutory income tax rate plus our blended state income tax rate. Our effective tax rate for the six months ended June 30, 2026 was higher than the statutory rate primarily due to the significant discrete items, including permanent differences recognized in connection with the Manager PSUs that vested during the six months ended June 30, 2026. Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP) Adjusted EBITDAX and Levered Free Cash Flow are supplemental non-GAAP financial measures used by our management to assess our operating results and liquidity. See “—Non-GAAP financial measures” section below for their definitions and application. 46 The following table presents a reconciliation of Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP) to net income (loss) and Levered Free Cash Flow (non-GAAP) to Net cash provided by operating activities, the most directly comparable financial measures, respectively calculated in accordance with GAAP: Six Months Ended June 30, 2026 2025 $ Change % Change (in thousands, except percentages) Net income (loss) $ 74,528 $ 168,412 $ (93,884) (56) % Adjustments to reconcile to Adjusted EBITDAX: Interest expense 204,397 148,400 Loss from extinguishment of debt 17,397 — Income tax expense (benefit) 87,648 43,670 Depreciation, depletion and amortization 712,129 579,629 Exploration expense 6,885 5,880 Non-cash (gain) loss on derivatives 181,539 (98,362) Impairment expense — 48,632 Non-cash equity-based compensation expense 44,709 119,493 (Gain) loss on sale of assets (10,690) (12,772) Other (income) expense (144) (231) Certain redeemable noncontrolling interest distributions made by OpCo (1) — (4,242) Transaction and nonrecurring expenses (2) 46,641 9,906 Settlement of acquired derivative contracts 122,632 34,895 Adjusted EBITDAX (non-GAAP) $ 1,487,671 $ 1,043,310 $ 444,361 43 % Adjustments to reconcile to Levered Free Cash Flow: Interest expense, excluding non-cash amortization of deferred financing costs, discounts, and premiums (196,164) (140,859) Loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts, and premiums (11,963) — Current income tax benefit (expense) (1,179) (17,486) Tax-related redeemable noncontrolling interest distributions made by OpCo — (260) Development of oil and natural gas properties (668,848) (472,253) Levered Free Cash Flow (non-GAAP) $ 609,517 $ 412,452 $ 197,065 48 % (1)In our calculation of Adjusted EBITDAX and Levered Free Cash Flow, we reflected Manager Compensation as if 100% of OpCo were owned and managed by the Company, to reflect consistent earnings and liquidity measures not impacted by the amount of OpCo’s ownership under management. After giving effect to the Corporate Simplification, the Company owns 100% of outstanding OpCo Units and no longer makes distributions to the holders of redeemable noncontrolling interests in OpCo. (2)Transaction and nonrecurring expenses of $46.6 million for the six months ended June 30, 2026 were primarily related to earn-out payments for the Ridgemar Acquisition, Vital Energy Merger transaction costs, capital markets transactions and divestiture and restructuring costs. Transaction and nonrecurring expenses of $9.9 million for the six months ended June 30, 2025 were primarily related to uncapitalized transaction costs related to the Ridgemar Acquisition and transaction costs related to our divestitures and the SilverBow Merger, partially offset by proceeds from a legal settlement. 47 Six Months Ended June 30, 2026 2025 $ Change % Change (in thousands, except percentages) Net cash provided by operating activities $ 1,115,979 $ 836,080 $ 279,899 33 % Changes in operating assets and liabilities 107,557 21,758 Certain redeemable noncontrolling interest distributions made by OpCo (1) — (4,242) Tax-related redeemable noncontrolling interest contributions (distributions) made by OpCo — (260) Transaction and nonrecurring expenses (2) 46,641 9,906 Loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts, and premiums (11,963) — Exploration expense 6,885 5,880 Other adjustments and operating activities 13,266 15,583 Development of oil and natural gas properties (668,848) (472,253) Levered Free Cash Flow (non-GAAP) $ 609,517 $ 412,452 $ 197,065 48 % (1)In our calculation of Adjusted EBITDAX and Levered Free Cash Flow, we reflected Manager Compensation as if 100% of OpCo were owned and managed by the Company, to reflect consistent earnings and liquidity measures not impacted by the amount of OpCo’s ownership under management. After giving effect to the Corporate Simplification, the Company owns 100% of outstanding OpCo Units and no longer makes distributions to the holders of redeemable noncontrolling interests in OpCo. (2)Transaction and nonrecurring expenses of $46.6 million for the six months ended June 30, 2026 were primarily related to earn-out payments for the Ridgemar Acquisition, Vital Energy Merger transaction costs, capital markets transactions and divestiture and restructuring costs. Transaction and nonrecurring expenses of $9.9 million for the six months ended June 30, 2025 were primarily related to uncapitalized transaction costs related to the Ridgemar Acquisition and transaction costs related to our divestitures and the SilverBow Merger, partially offset by proceeds from a legal settlement. Adjusted EBITDAX (non-GAAP) increased by $444.4 million, or 43%, in the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily driven by additional production from the Vital Energy Merger and increased oil pricing. Levered Free Cash Flow (non-GAAP) increased by $197.1 million, or 48%, in the six months ended June 30, 2026 compared to the six months ended June 30, 2025, primarily driven by increased Adjusted EBITDAX, partially offset by $196.6 million of increased development of oil and natural gas properties expenditures and additional interest expense. Liquidity and capital resources Our primary sources of liquidity are cash on hand, cash flow from operations, proceeds from equity and debt offerings and borrowings under our senior secured reserve-based revolving credit agreements. Our primary expected uses of capital are for dividends to shareholders, our share repurchase program, debt repayment, including open market repurchases of our Senior Notes, development of our existing assets and acquisitions. Our development program is designed to prioritize the generation of meaningful free cash flow and attractive risk-adjusted returns and is inherently flexible, with the ability to scale our capital program as necessary to react to the existing market environment and ongoing asset performance. See “—Development program and capital budget” above for additional discussion of our capital program. We plan to continue our practice of entering into economic hedging arrangements to reduce the impact of the near-term volatility of commodity prices and the resulting impact on our cash flow from operations. A key tenet of our focused risk management efforts is an active economic hedge strategy to mitigate near-term price volatility while maintaining long-term exposure to underlying commodity prices. Our commodity derivative program focuses on entering into forward commodity contracts when investment decisions regarding reinvestment in existing assets or new acquisitions are finalized, targeting economic hedges for a portion of expected production generated by the capital investment as well as adding incremental derivatives to our production base over time. Our active derivative program allows us to protect margins and corporate returns through commodity cycles. 48 The following table presents our cash balances and outstanding borrowings at the end of each period presented: June 30, 2026 December 31, 2025 (in thousands) Cash and cash equivalents $ 264,882 $ 10,157 Long-term debt 5,166,022 5,524,128 Based on our planned capital spending, our forecasted cash flows and projected levels of indebtedness, we expect to maintain compliance with the covenants under our debt agreements. Further, based on current market indications, we expect to meet in the ordinary course of business other contractual cash commitments to third parties pursuant to the various agreements described under the heading “Contractual obligations” in our Annual Report, recognizing we may be required to meet such commitments even if our business plan assumptions were to change. Cash flows The following table summarizes our cash flows for the periods indicated: Six Months Ended June 30, 2026 2025 (in thousands) Net cash provided by operating activities $ 1,115,979 $ 836,080 Net cash used in investing activities (1,003,650) (1,269,111) Net cash provided by (used in) financing activities (576,492) 213,380 Net cash provided by operating activities. Net cash provided by operating activities for the six months ended June 30, 2026 increased by $279.9 million, or 33%, compared to the six months ended June 30, 2025 primarily due to higher net income after adjusting for non-cash items. Net cash used in investing activities. Net cash used in investing activities for the six months ended June 30, 2026 decreased by $265.5 million, or 21%, compared to the six months ended June 30, 2025, primarily due to $529.9 million lower acquisitions of oil and natural gas properties in 2026 partially offset by $175.3 million additional cash used in our development capital expenditures. Net cash provided by (used in) financing activities. Net cash used in financing activities for the six months ended June 30, 2026 was $576.5 million, primarily a result of net repayments of our long-term debt balances and our dividend payments. Net cash provided by financing activities for the six months ended June 30, 2025 was $213.4 million, primarily a result of net cash received in Revolving Credit Facility borrowings, partially offset by our dividend payments and cash distributions to our redeemable noncontrolling interests. Debt agreements Senior Notes 2031 Convertible Notes In March 2026, we issued $690.0 million aggregate principal amount of 2.750% Convertible Senior Notes due 2031 (the “2031 Convertible Notes”) at par. The 2031 Convertible Notes bear interest at an annual rate of 2.750%, which is payable on March 15 and September 15 of each year, beginning on September 15, 2026, and mature on March 15, 2031, unless earlier converted or redeemed or purchased by the Company. The net proceeds of the 2031 Convertible Notes were approximately $671.0 million after deducting the initial purchasers’ discount and offering expenses. The net proceeds of the 2031 Convertible Notes were used in part to redeem all of our outstanding 2028 Notes (as defined below) as discussed below. Prior to December 15, 2030, the 2031 Convertible Notes are convertible only in certain circumstances and during specified periods. Thereafter, they are convertible at the noteholders’ election until shortly before the maturity date. Upon conversion, we may settle the conversions by paying or delivering, as applicable, in cash, shares of Class A Common Stock, or a combination 49 thereof, at our election. The 2031 Convertible Notes have an initial conversion rate of 67.1456 shares of Class A Common Stock per each $1,000 principal amount, which represents an initial conversion price of approximately $14.89 per share of Class A Common Stock. In connection with the issuance of the 2031 Convertible Notes, we paid $56.6 million to enter into capped call transactions with certain financial institution counterparties designed to reduce potential dilution upon conversion of the 2031 Convertible Notes and/or offset cash payments in excess of the principal amount of the converted notes, in each case subject to the initial cap price of $22.48 per share of Class A Common Stock. The 2031 Convertible Notes are the Company’s senior, unsecured obligations and are (i) equal in right of payment with 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’s subsidiaries, and the Company’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’s subsidiaries, the 2031 Convertible Notes are structurally subordinated to all indebtedness and other liabilities, including the Revolving Credit Facility, the CRF Credit 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 Company’s subsidiaries. 2028 Notes At December 31, 2025, we had $500.0 million outstanding aggregate principal amount of 9.250% senior notes due 2028 (the “2028 Notes”). In March 2026, we elected to redeem all of the remaining 2028 Notes (the “2028 Notes Redemption”), at a price of 102.3125%. As a result of the 2028 Notes Redemption, we incurred a loss on the extinguishment of debt of approximately $17.0 million, including $5.4 million related to the non-cash write-off of outstanding deferred financing costs, discounts, and premiums. 2029 Notes 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. Revolving Credit Facility We are party to a Revolving Credit Facility with Wells Fargo Bank, N.A., as administrative agent for the lenders and letter of credit issuer, and the lenders from time to time party thereto. On May 18, 2026, we entered into the Fifteenth Amendment (the “CEF Credit Agreement Amendment”) to the credit agreement governing our Revolving Credit Facility, pursuant to which, among other things, the maturity date was extended to May 19, 2031. The borrowing base under the Revolving Credit Facility was $3.5 billion and $3.9 billion as of June 30, 2026 and December 31, 2025, respectively. At June 30, 2026, our elected commitment amount was approximately $2.0 billion and we had no outstanding borrowings, $16.6 million in outstanding letters of credit and approximately $2.0 billion of available borrowings. Borrowings under the Revolving Credit Facility bear interest at either a (i) U.S. dollar alternative base rate based on the prime rate, the federal funds effective rate or an adjusted SOFR, plus an applicable margin, or (ii) SOFR, plus an applicable margin, at the election of the borrowers. The applicable margin varies based upon our borrowing base utilization then in effect. The fee payable for the unused revolving commitments at June 30, 2026 is 0.375% per year. Our weighted average interest rate on loan amounts outstanding as of December 31, 2025 was 5.56%. We had no borrowings outstanding under the Revolving Credit Facility at June 30, 2026. At June 30, 2026, we were in compliance with each of the covenants under the Revolving Credit Facility and expect to remain in compliance with these covenants for the foreseeable future. Crescent Royalty Finance Credit Facility In February 2026, one of our subsidiaries, CRF, entered into a senior secured reserve-based revolving credit agreement with Wells Fargo Bank, N.A., as administrative agent for the lenders and letter of credit issuer, and the lenders from time to time party thereto (the “CRF Credit Facility”). The CRF Credit Facility provides for a $1.0 billion aggregate maximum credit 50 amount senior secured reserve-based revolving credit facility, with an initial borrowing base and aggregate elected commitment amount of $365.0 million consisting of $230.0 million under the revolving facility and a $135.0 million term loan (“CRF Term Loan”). As of June 30, 2026, $45.5 million remained outstanding under the CRF Term Loan. Revolving loans under the CRF Credit Facility mature on February 23, 2031, and initial term loans under the CRF Credit Facility mature on February 23, 2029. The borrowing base is subject to semi-annual scheduled redeterminations on or about April 1st and October 1st of each year. The obligations under the CRF Credit Facility are secured by liens on collateral granted by CRF, as borrower, and the guarantors under the related security documents, including, without limitation, oil and gas properties and related assets, as-extracted collateral in the form of production and proceeds attributable to mortgaged properties, equity interests in restricted subsidiaries owned by the borrower or subsidiary guarantors, certain indebtedness owed to the borrower or subsidiary guarantors, and deposit and securities accounts, in each case subject to permitted liens, excluded assets and other exceptions. The security documents include the security agreement, pledge agreement, mortgages, account control agreements and other instruments executed to secure or perfect the obligations under the facility. In connection with each redetermination of the borrowing base, the borrower must maintain mortgages on properties sufficient to satisfy the collateral coverage minimum, which requires that mortgaged properties represent at least 85% of the PV-9 of the credit parties’ total proved reserves included in the initial reserve report and, thereafter, the most recent reserve report. The borrower’s domestic subsidiaries are required to be guarantors under the CRF Credit Facility, subject to certain exceptions. Interest Borrowings under the CRF Credit Facility bear interest at either (i) a U.S. dollar alternative base rate based on the prime rate, the federal funds effective rate or an adjusted SOFR, plus an applicable margin or (ii) SOFR, plus an applicable margin, at the election of CRF. The applicable margin and fee payable for the unused revolving commitments varies based upon CRF’s borrowing base utilization then in effect. The weighted average interest rates on the CRF Credit Facility and the CRF Term Loan amounts outstanding as of June 30, 2026 were 6.446% and 6.946%, respectively. Covenants The CRF Credit Facility contains certain covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity and commodity swap agreements, liens and other transactions without the prior consent of our lenders. We are subject to (i) maximum leverage ratio and (ii) current ratio financial covenants calculated as of the last day of each fiscal quarter, beginning with the fiscal quarter ending on June 30, 2026. The CRF Credit Facility also contains representations, warranties, indemnifications and affirmative and negative covenants, including events of default relating to nonpayment of principal, interest or fees, inaccuracy of representations or warranties in any material respect when made or when deemed made, violation of covenants, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default occurs and we are unable to cure such event of default, the lenders will be able to accelerate maturity and exercise other rights and remedies. As of June 30, 2026, we were in compliance with each of the covenants under the CRF Credit Facility and expect to remain in compliance with these covenants for the foreseeable future. Capital expenditures Our acquisition and development expenditures consist of acquisitions of proved and unproved property, expenditures associated with the development of our oil and natural gas properties and other asset additions. Cash expenditures for drilling, completion and recompletion activities and related facilities are presented as “Development of oil and natural gas properties” in investing activities on our condensed consolidated statements of cash flows. We expect to fund our 2026 capital program, excluding acquisitions, through cash flow from operations. The amount and timing of capital expenditures on development of oil and natural gas properties is substantially within our control due to the held-by-production nature of our assets. We regularly review our capital expenditures throughout the year and could choose to adjust our investments based on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGLs, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and the related Standardized Measure. These risks could materially affect our business, financial condition and results of operations. The table below presents our capital expenditures and related metrics that we use to evaluate our business for the periods presented: 51 Six Months Ended June 30, 2026 2025 (in thousands) Total development of oil and natural gas properties $ 668,848 $ 472,253 Change in accruals or other non-cash adjustments (17,514) 3,799 Cash used in development of oil and natural gas properties 651,334 476,052 Cash used in acquisition of oil and natural gas properties (1) 354,423 884,366 Non-cash acquisition of oil and natural gas properties 13,528 82,145 Total expenditures on acquisition and development of oil and natural gas properties $ 1,019,285 $ 1,442,563 (1)Excludes $14.1 million of accounts receivable related to the Ridgemar Acquisition customary purchase price adjustments as of June 30, 2025. Our cash used in the development of oil and natural gas properties was higher during the six months ended June 30, 2026, compared to the six months ended June 30, 2025. The increase is related to an increase in our operations. We used cash of $354.4 million in the six months ended June 30, 2026 for the acquisition of oil and natural gas properties, primarily related to the 2026 Minerals Acquisitions, as compared to $884.4 million in 2025 for the acquisition of oil and natural gas properties, primarily related to the Ridgemar Acquisition (see Notes to condensed consolidated financial statements, NOTE 3 – Acquisitions and Divestitures included in Part I. Item 1. Financial Statements of this Quarterly Report). Contractual obligations As of June 30, 2026, there have been no material changes to the contractual obligations previously disclosed in our Annual Report. Dividends Our future dividends depend on our level of earnings, financial requirements and other factors and will be subject to approval by our Board of Directors, applicable law and the terms of our existing debt documents, including the Revolving Credit Facility and the indentures governing the Senior Notes. We paid cash dividends of $0.24 per share of our Class A Common Stock to shareholders during the six months ended June 30, 2026. On August 3, 2026, the Board of Directors approved a quarterly cash dividend of $0.12 per share, or $0.48 per share on an annualized basis, to be paid to shareholders of our Class A Common Stock with respect to the second quarter of 2026. The quarterly dividend is payable on August 31, 2026 to shareholders of record as of the close of business on August 17, 2026. The payment of quarterly cash dividends is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and approval by our Board of Directors. In light of current economic conditions, management will evaluate any future increases in cash dividends on a quarterly basis. Summarized Supplemental Subsidiary Financial Information (UNAUDITED) CEC is a holding company that conducts substantially all of its business through its consolidated subsidiaries, including (i) OpCo, which is wholly owned by CEC, and (ii) Crescent Energy Finance LLC (“CEF”) and Crescent Royalty Finance LLC (“CRF”), each of which is wholly owned by OpCo. OpCo has no material operations, cash flows, assets or liabilities other than its investments in CEF and CRF. The assets and liabilities of OpCo represent substantially all of our consolidated assets and liabilities, except for certain parent company items held by CEC such as current and deferred taxes, CEC’s 2031 Convertible Notes (as defined within NOTE 7 – Debt), and certain liabilities under the Management Agreement (as defined within NOTE 11 – Related Party Transactions). Crescent’s consolidated balance sheets and consolidated statement of operations are materially the same as CEF with the exception of the below information. 52 Selected Summarized Balance Sheet Information: As of June 30, 2026 (in thousands) Minerals and royalties (CRF) Assets: Current assets $ 54,803 Property and equipment, net 665,758 Other noncurrent assets 4,054 Liabilities: Current liabilities 11,462 Long-term debt 273,861 Equity: Total equity 438,395 Other entities (CEF and CEC) Debt: CEF long-term debt 4,220,767 CEC long-term debt 671,394 Selected Summarized Statement of Operations: Three Months Ended Six Months Ended June 30, 2026 (in thousands) Minerals and royalties (CRF) Revenues $ 62,569 $ 107,078 Operating expense 5,175 9,401 Gain (loss) on derivatives 8,372 (14,705) Interest expense (5,653) (8,265) Net income (loss) 42,332 42,861 Critical accounting policies and estimates This discussion and analysis of our financial condition and results of operations are based upon our unaudited condensed consolidated financial statements. A complete list of our significant accounting policies is described in NOTE 2 – Summary of Significant Accounting Policies in our audited financial statements as of and for the year ended December 31, 2025 in our Annual Report. Refer also to “Critical accounting estimates” in Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report. There have been no changes to our significant accounting policies and critical accounting estimates as of June 30, 2026. Non-GAAP financial measures Our MD&A includes financial and liquidity measures that have not been calculated in accordance with U.S. GAAP. These non-GAAP measures include the following: •Adjusted EBITDAX; and •Levered Free Cash Flow These are supplemental non-GAAP financial and liquidity measures used by our management to assess our operating results and assist us to make our investment decisions. We believe that the presentation of these non-GAAP financial measures provides investors with greater transparency with respect to our results of operations, as well as liquidity and capital resources, and that these measures are useful for period-to-period comparison of results. 53 We define Adjusted EBITDAX as net income (loss) before interest expense, loss from extinguishment of debt, income tax expense (benefit), depreciation, depletion and amortization, exploration expense, non-cash gain (loss) on derivatives, impairment expense, equity-based compensation, (gain) loss on sale of assets, other (income) expense and transaction and nonrecurring expenses. Additionally, we further adjust for certain redeemable noncontrolling interest distributions made by OpCo and settlement of acquired derivative contracts. We included “Certain redeemable noncontrolling interest distributions made by OpCo” to reflect Manager Compensation as if 100% of OpCo were owned and managed by the Company, to reflect consistent earnings and liquidity measures not impacted by the amount of OpCo’s ownership under management. After giving effect to the Corporate Simplification, the Company owns 100% of outstanding OpCo Units and no longer makes distributions to the holders of redeemable noncontrolling interests in OpCo. Adjusted EBITDAX is not a measure of performance as determined by GAAP. We believe Adjusted EBITDAX is a useful performance measure because it allows for an effective evaluation of our operating performance when compared against our peers, without regard to our financing methods, corporate form or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP, of which such measure is the most comparable GAAP measure. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax burden, as well as the historic costs of depreciable assets, none of which are reflected in Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or nonrecurring items. Our computations of Adjusted EBITDAX may not be identical to other similarly titled measures of other companies. In addition, the Revolving Credit Facility and Senior Notes include a calculation of Adjusted EBITDAX for purposes of covenant compliance. We define Levered Free Cash Flow as Adjusted EBITDAX less interest expense, excluding non-cash amortization of deferred financing costs, discounts, and premiums, loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts and premiums, current income tax benefit (expense), tax-related redeemable noncontrolling interest distributions made by OpCo and development of oil and natural gas properties. Levered Free Cash Flow does not take into account amounts incurred on acquisitions. Levered Free Cash Flow is not a measure of liquidity as determined by GAAP. Levered Free Cash Flow is a supplemental non-GAAP liquidity measure that is used by our management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Levered Free Cash Flow is a useful liquidity measure because it allows for an effective evaluation of our operating and financial performance and the ability of our operations to generate cash flow that is available to reduce leverage or distribute to our equity holders. Levered Free Cash Flow should not be considered as an alternative to, or more meaningful than, Net cash flow provided by operating activities as determined in accordance with GAAP, of which such measure is the most comparable GAAP measure, or as an indicator of actual liquidity, operating performance or investing activities. Our computations of Levered Free Cash Flow may not be comparable to other similarly titled measures of other companies. Adjusted EBITDAX and Levered Free Cash Flow should be read in conjunction with the information contained in our condensed consolidated financial statements prepared in accordance with GAAP. For a reconciliation of these non-GAAP measures to the nearest comparable GAAP measures, see “—Results of Operations—Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP)” above.