Crescent Energy Co (CRGY)
SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1311 Crude Petroleum & Natural Gas
SEC company page: https://www.sec.gov/edgar/browse/?CIK=1866175. Latest filing source: 0001866175-26-000026.
Selected Fundamentals
| Metric | Value | Unit | FY | Filed |
|---|---|---|---|---|
| Revenue | 3,579,782,000 | USD | 2025 | 2026-02-25 |
| Net income | 132,906,000 | USD | 2025 | 2026-02-25 |
| Assets | 12,443,207,000 | USD | 2025 | 2026-02-25 |
Financials
Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-25. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001866175.json. Derived margins are computed from the extracted annual SEC facts.
| Metric | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 |
|---|---|---|---|---|---|---|---|
| Revenue | 1,087,240,000 | 754,221,000 | 1,476,977,000 | 3,057,065,000 | 2,382,602,000 | 2,930,919,000 | 3,579,782,000 |
| Net income | 0.00 | 0.00 | -19,376,000 | 96,674,000 | 67,610,000 | -114,605,000 | 132,906,000 |
| Operating income | 227,114,000 | -373,628,000 | 483,739,000 | 1,284,165,000 | 324,740,000 | 218,462,000 | 229,279,000 |
| Assets | 3,907,369,000 | 5,157,462,000 | 6,019,849,000 | 6,803,335,000 | 9,160,649,000 | 12,443,207,000 | |
| Liabilities | 1,014,209,000 | 2,137,805,000 | 2,720,855,000 | 3,167,617,000 | 4,792,689,000 | 7,277,772,000 | |
| Stockholders' equity | 694,644,000 | 862,291,000 | 1,734,510,000 | 3,139,631,000 | 5,165,435,000 | ||
| Cash and cash equivalents | 19,894,000 | 36,861,000 | 128,578,000 | 0.00 | 2,974,000 | 132,818,000 | 10,157,000 |
| Net margin | 0.00% | 0.00% | -1.31% | 3.16% | 2.84% | -3.91% | 3.71% |
| Operating margin | 20.89% | -49.54% | 32.75% | 42.01% | 13.63% | 7.45% | 6.40% |
Financial Charts
Quarterly
Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-04. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001866175.json.
| Quarter | End Date | Revenue | Net Income | Diluted EPS | Method |
|---|---|---|---|---|---|
| 2023-Q2 | 2023-06-30 | 492,339,000 | 5,151,000 | reported discrete quarter | |
| 2023-Q3 | 2023-09-30 | 642,398,000 | -52,870,000 | reported discrete quarter | |
| 2023-Q4 | 2023-12-31 | 657,728,000 | 55,535,000 | derived Q4 = FY annual - nine-month YTD | |
| 2024-Q1 | 2024-03-31 | 657,473,000 | -24,168,000 | reported discrete quarter | |
| 2024-Q2 | 2024-06-30 | 653,283,000 | 37,547,000 | reported discrete quarter | |
| 2024-Q3 | 2024-09-30 | 744,874,000 | -9,945,000 | reported discrete quarter | |
| 2024-Q4 | 2024-12-31 | 875,289,000 | -118,039,000 | derived Q4 = FY annual - nine-month YTD | |
| 2025-Q1 | 2025-03-31 | 950,172,000 | -2,150,000 | reported discrete quarter | |
| 2025-Q2 | 2025-06-30 | 897,983,000 | 153,221,000 | reported discrete quarter | |
| 2025-Q3 | 2025-09-30 | 866,579,000 | -9,507,000 | reported discrete quarter | |
| 2025-Q4 | 2025-12-31 | 865,047,000 | -8,661,000 | derived Q4 = FY annual - nine-month YTD | |
| 2026-Q1 | 2026-03-31 | 1,182,830,000 | -419,847,000 | reported discrete quarter |
Quarterly Charts
Macro Cross-References
- CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
- UNRATE - Unemployment Rate
- FEDFUNDS - Federal Funds Effective Rate
- CES0500000003 - Average Hourly Earnings of All Employees, Total Private
- DFEDTARU - Federal Funds Target Range - Upper Limit
- DFEDTARL - Federal Funds Target Range - Lower Limit
- DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
- DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
- DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
- DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
- T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
- CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
- CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
- CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
- CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
- PCEPI - Personal Consumption Expenditures: Chain-type Price Index
- PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
- PPIACO - Producer Price Index by Commodity: All Commodities
- T10YIE - 10-Year Breakeven Inflation Rate
- U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
- PAYEMS - All Employees, Total Nonfarm
- CIVPART - Labor Force Participation Rate
- EMRATIO - Employment-Population Ratio
- UNEMPLOY - Unemployed
- CE16OV - Employment Level
- ICSA - Initial Claims
- JTSJOL - Job Openings: Total Nonfarm
- JTSQUR - Quits: Total Nonfarm
- GDPC1 - Real Gross Domestic Product
- A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
- INDPRO - Industrial Production: Total Index
- TCU - Capacity Utilization: Total Index
- HOUST - New Privately-Owned Housing Units Started: Total Units
- PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
- RSAFS - Advance Retail Sales: Retail Trade
- PCE - Personal Consumption Expenditures
- DSPIC96 - Real Disposable Personal Income
- PSAVERT - Personal Saving Rate
- M2SL - M2
- BOPGSTB - U.S. International Trade in Goods and Services: Balance
- MSPUS - Median Sales Price of Houses Sold for the United States
- HSN1F - New One Family Houses Sold: United States
- RHORUSQ156N - Homeownership Rate in the United States
- TTLCONS - Total Construction Spending: Total Construction in the United States
- RRVRUSQ156N - Rental Vacancy Rate in the United States
- TOTALSL - Total Consumer Credit Owned and Securitized
- REVOLSL - Revolving Consumer Credit Owned and Securitized
- DRCCLACBS - Delinquency Rate on Credit Card Loans, All Commercial Banks
- GDP - Gross Domestic Product
- GPDI - Gross Private Domestic Investment
- GCE - Government Consumption Expenditures and Gross Investment
- PCEC - Personal Consumption Expenditures
- NETEXP - Net Exports of Goods and Services
- GFDEBTN - Federal Debt: Total Public Debt
- GFDEGDQ188S - Federal Debt: Total Public Debt as Percent of Gross Domestic Product
- FYFSD - Federal Surplus or Deficit
- FGRECPT - Federal Government Current Receipts
- FGEXPND - Federal Government: Current Expenditures
- MANEMP - All Employees, Manufacturing
- USCONS - All Employees, Construction
- USTRADE - All Employees, Retail Trade
- USFIRE - All Employees, Financial Activities
- USGOVT - All Employees, Government
- AWHAETP - Average Weekly Hours of All Employees, Total Private
- DGORDER - Manufacturers' New Orders: Durable Goods
- NEWORDER - Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft
- BUSINV - Total Business Inventories
- EXPGS - Exports of Goods and Services
- IMPGS - Imports of Goods and Services
- IR - Import Price Index (End Use): All Commodities
- PPIFIS - Producer Price Index by Commodity: Final Demand
Latest quarter (10-Q)
Latest 10-Q source: 0001866175-26-000090.
Item 2. Management’s discussion and analysis of financial condition and results of operations
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"), as well as our unaudited condensed consolidated financial statements for the three months ended March 31, 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 months ended March 31, 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 in 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. 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 quarter of 2026, 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.
During the three months ended March 31, 2026, no impairment expense was incurred. During the three months ended March 31, 2025, we recorded an impairment expense of $45.6 million 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
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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 in 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. 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 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, 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 C
[Excerpt truncated for page length; source filing is linked above.]
Latest 10-K MD&A
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
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, 2025 and 2024. Refer to our 2024 Annual Report filed February 26, 2025 for discussion and analysis of the changes in results of operations between the years
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ended December 31, 2024 and 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.
Business overview
Crescent is a differentiated 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 a deep, high-quality development inventory. Our activities are focused in the 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 Eagle Ford. Our Class A Common Stock trades on the NYSE under the symbol “CRGY.”
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, including the conflict with Iran, recent developments in Venezuela, supply chain constraints, elevated interest rates, U.S. international trade and tariff policy developments 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, OPEC announced that it is phasing out oil output cuts by increasing 411,000 barrels per day, each month from May to July 2025 and then increasing to 548,000 barrels per day in August 2025. While actual production significantly diverged from these announced targets, as several OPEC members were unable to meet the planned increases when others continued to overproduce, the actions of OPEC with respect to oil production levels and announcements of potential changes in such 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 remained relatively stable through 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 inflation and certain other market pressures have caused the U.S. Federal Reserve and other central banks to increase interest rates in 2022 and 2023. Although the U.S. Federal Reserve made cuts to benchmark interest rates in 2024 and in 2025, there is no guarantee that 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 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, 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,
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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."
Capital market transactions
Vital Exchange Offer
On January 2, 2026, in connection with the Vital Energy Merger, Crescent Energy Finance LLC completed its previously announced offers to eligible holders to exchange (the “Exchange Offers”) (i) any and all of the 7.750% senior notes due 2029 (the “Vital 2029 Notes”) of Crescent Energy Finance LLC, as successor in interest to Vital, for up to approximately $298.2 million aggregate principal amount of new 7.750% senior notes due 2029 of Crescent Energy Finance LLC (the “Crescent 2029 Notes”); and (ii) any and all of the 9.750% senior notes due 2030 (the “Vital 2030 Notes”) of Crescent Energy Finance LLC, as successor in interest to Vital, for up to approximately $302.4 million aggregate principal amount of new 9.750% senior notes due 2030 issued by Crescent Energy Finance LLC (the “Crescent 2030 Notes”). Following the settlement of the Exchange Offers, $2.9 million aggregate principal amount of the Vital 2029 Notes, $294.8 million aggregate principal amount of the Crescent 2029 Notes, $65.0 million aggregate principal amount of the Vital 2030 Notes and $237.2 million aggregate principal amount of the Crescent 2030 Notes remain outstanding, respectively.
2025 Senior Notes Offerings
In June 2025, we commenced a cash tender offer (the "Tender Offer") to purchase a portion of our outstanding 9.250% Senior Notes due 2028 (the "2028 Notes"), pursuant to which approximately $306.1 million aggregate principal amount of 2028 Notes were validly tendered and not validly withdrawn at or prior to July 22, 2025, the final tender date. In addition to the Tender Offer, we elected to redeem (the "2028 Notes Redemption") an aggregate principal amount of the 2028 Notes equal to $193.9 million, at a price of 104.625% of the unpaid principal amount of the 2028 Notes, plus accrued and unpaid interest, if any, to, but excluding, July 25, 2025, the redemption date. After giving effect to the 2028 Notes Redemption and the Tender Offer, the aggregate principal amount of the 2028 Notes outstanding is $500.0 million. Combined, we purchased the 2028 Notes at a blended price of 104.472% of par and incurred a loss on the extinguishment of debt of approximately $29.2 million, including the write-off of associated deferred financing costs, during the year ended December 31, 2025.
In July 2025, we issued $600.0 million aggregate principal amount of 8.375% senior notes due 2034 (the "2034 Notes") at par (the "2034 Notes Offering"). The 2034 Notes bear interest at an annual rate of 8.375%, which is payable on January 15 and July 15 of each year, and mature on January 15, 2034. The proceeds from the 2034 Notes Offering were approximately $588.1 million after deducting the initial purchasers' discount and offering expenses. We used the net proceeds to finance the consideration of the Tender Offer and the 2028 Notes Redemption and to repay a portion of our outstanding balance under our Revolving Credit Facility.
Corporate Simplification
In April 2025, we announced that our corporate structure had been simplified through the elimination of the Company’s Up-C structure through the exercise by the holders of all remaining shares of Class B Common Stock of their redemption rights with respect to all of their OpCo Units (the “Corporate Simplification”). Prior to the Corporate Simplification, the Up-C structure provided for holders of Crescent’s then-outstanding Class B Common Stock, which had voting (but no economic) rights with respect to Crescent, to hold a corresponding amount of economic, non-voting units of OpCo (“OpCo Units”), which were generally redeemable or exchangeable for Class A Common Stock on the terms and conditions set forth in the OpCo LLC Agreement. Pursuant to the aforementioned exercise of such right in the Corporate Simplification, all OpCo Units (other than those held by Crescent) were exchanged for an equivalent number of shares of Class A Common Stock and all outstanding shares of Class B Common Stock were cancelled. As a result of the Corporate Simplification, all of the Company’s common stockholders now hold Class A Common Stock. See NOTE 14 – Related Party Transactions for more information.
2025 Equity Transactions
In March 2025, Independence Energy Aggregator L.P., the entity through which certain private investors in affiliated KKR entities held their interests in us, exercised its redemption right with respect to 2.9 million OpCo Units, and such OpCo Units were exchanged for an equivalent number of shares of Class A Common Stock and a corresponding number of shares of Class B Common Stock were cancelled (the "2025 Class A Redemption"). The shares of Class A Common Stock were sold by Independence Energy Aggregator L.P. at a price per share of $9.91, pursuant to Rule 144, through a broker-dealer. We did not receive any proceeds or incur any material expenses related to the 2025 Class A Redemption.
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2024 Senior Notes Offerings
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 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.
All issuances of the 2033 Notes are treated as a single series of securities under the indenture governing the 2033 Notes, will vote together as a single class, and have substantially identical terms, other than the issue date and the issue price.
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", 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") following such cash tender offer of all of the aggregate principal amount of the 2026 Notes outstanding for $714.8 million after including extinguishment costs. We used the proceeds from the December 2024 Offering to repay the amounts outstanding under our Revolving Credit Facility.
All issuances of the 2032 Notes are treated as a single series of securities under the indenture governing the 2032 Notes, will vote together as a single class, and have substantially identical terms, other than the issue date and the issue price.
2024 Equity Transactions
In December 2024, we conducted an underwritten public offering of 24.7 million shares of Class A Common Stock at a price to the public of $14.00 per share (not including underwriter discounts and commissions) (the "December 2024 Equity Issuance"). This included 3.2 million shares of Class A Common Stock that were issued upon the underwriters exercise of their 30-day option to purchase additional shares to cover over-allotments pursuant to the related underwriting agreement. We received net proceeds of approximately $329.3 million from the 2024 Equity Issuance, after deducting underwriting fees and expenses.
On April 1, 2024, Independence Energy Aggregator L.P., the entity through which certain private investors in affiliated KKR entities held their interests in us, exercised its redemption right with respect to 6.0 million OpCo Units, and such OpCo Units were exchanged for an equivalent number of shares of Class A Common Stock and a corresponding number of shares of Class B Common Stock were cancelled (the "April 2024 Class A Redemption"). The shares of Class A Common Stock were subsequently sold by Independence Energy Aggregator L.P. at a price per share of $10.74, pursuant to Rule 144, through a broker-dealer. We did not receive any proceeds or incur any material expenses related to the April 2024 Class A Redemption.
In March 2024, 16.1 million OpCo Units were acquired from Independence Energy Aggregator L.P. and we cancelled a corresponding number of shares of Class B Common Stock (the "March 2024 Redemption"). Of the total OpCo Units acquired, 13.8 million were exchanged for shares of Class A Common Stock, which were subsequently sold in an underwritten public offering at a price to the public of $10.50 per share, or a net price of $9.87 per share after deducting the underwriters' discounts and commissions, from which we did not receive any proceeds, nor incur any material expenses with respect to such acquisition. In connection with the underwritten public offering, we repurchased 2.3 million OpCo Units from Independence Energy Aggregator L.P. for $22.7 million in cash and we cancelled a corresponding number of shares of Class B Common Stock (the "March 2024 Repurchase," together with the March 2024 Redemption, the "March 2024 Equity Transactions").
Acquisitions, divestitures and related reorganization
Acquisitions and related reorganization
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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 Crescent Energy Finance LLC. 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 NOTE 3 – Acquisitions and Divestitures for additional information.
Ridgemar Acquisition
On December 3, 2024, we entered into the Ridgemar Acquisition Agreement, pursuant to which we acquired all of the outstanding equity interests in Ridgemar. On January 31, 2025, we acquired all of the outstanding equity interests in Ridgemar for $807.2 million in cash and 5.5 million shares of our Class A Common Stock. 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. We accounted for the Ridgemar Acquisition as an asset acquisition. See NOTE 3 – Acquisitions and Divestitures for additional information.
SilverBow Merger
On July 30, 2024, we consummated the SilverBow Merger. Immediately following the SilverBow Merger, Crescent Energy Company completed a series of internal transactions following which the assets of 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.
Other Acquisitions
In the first quarter of 2026, in a series of transactions, we acquired a portfolio of mineral and royalty interests located in the Eagle Ford from unrelated third-parties for an aggregate consideration of approximately $355.3 million, subject to customary purchase price adjustments.
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 (the “Webb Gas Acquisition”).
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, subject to customary purchase price adjustments (the "Minerals Acquisition").
In October 2024, we acquired from unaffiliated third parties certain interests in oil and gas properties, rights and related assets located in Atascosa, Frio, La Salle and McMullen Counties, Texas for aggregate consideration of approximately $156.0 million, including certain customary purchase price adjustments in the Central Eagle Ford Acquisition.
In February 2024, we acquired a portfolio of oil and natural gas mineral interests located in the Karnes Trough of the Eagle Ford Basin from an unrelated third-party (the "Eagle Ford Minerals Acquisition") for total cash consideration of approximately $25.0 million, including customary purchase price adjustments. The purchase price was funded using borrowings under our Revolving Credit Facility.
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Divestitures
During 2025, we entered into agreements with certain unrelated third-party buyers to sell non-core assets as part of our previously announced non-core asset divestiture program for total consideration in excess of $900.0 million, subject to customary purchase price adjustments and transaction costs, and we received $847.1 million in aggregate cash proceeds after preliminary customary purchase price adjustments. In connection with these transactions, we performed an assessment of the fair value of the associated net assets and liabilities and determined certain of those assets were impaired, and as such, we recorded impairment expense of $233.7 million to write down those assets to the estimated transaction price less cost to sell. In addition, we recorded a gain of $147.5 million on the sale of certain other assets.
Income Taxes
Crescent is a holding company and its sole material asset is OpCo Units. OpCo is a partnership and is generally not subject to U.S. federal and certain state taxes. Crescent is subject to U.S. federal and certain state taxes on our allocable share of any taxable income of OpCo. Taxable income or loss generated by OpCo is generally allocated and passed through to the holders of OpCo Units, including Crescent, based on their proportionate share of OpCo Unit ownership. Following the 2025 Class A Redemption and the Corporate Simplification, the Company is the sole holder of all outstanding OpCo Units. For additional information regarding income taxes, see "Notes to Consolidated Financial Statements—NOTE 11 – Income Taxes" in “Part II., Item 8. Financial Statements and Supplementary Data” of this Annual Report for more information. Following the 2025 Class A Redemption and the Corporate Simplification, The Company is the sole holder of all outstanding OpCo Units.
On July 4, 2025, the OBBBA was enacted into law. The OBBBA is a significant piece of tax legislation that includes provisions that permanently restore an EBITDA-based section 163(j) calculation for tax years beginning after December 31, 2024 and 100% bonus depreciation under section 168(k) for property acquired and placed in service after January 19, 2025, deferring the recognition of a significant portion of current federal tax for multiple years.
Stewardship
We seek to strategically improve 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 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.
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)
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Development program and capital budget
Our development program, which consists of expenditures for drilling and completion 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.
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 activities, prevailing and anticipated prices for oil, gas and NGLs and resulting well economics, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners.
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. Pricing of commodities are subject to supply and demand as well as seasonal, political and other conditions that we generally cannot control. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. The following table illustrates our production revenue mix for each of the periods presented:
Year Ended December 31,
2025
2024
2023
Oil
69
%
76
%
76
%
Natural gas
20
%
13
%
16
%
NGLs
11
%
11
%
8
%
In addition, revenue from our midstream assets is supported by commercial agreements that have established minimum volume commitments. These midstream revenues comprise the majority of our midstream and other revenue. Midstream and other revenue accounts for 5% or less of our total revenues for each of the years ended December 31, 2025, 2024 and 2023.
Production volumes sold
The following table presents historical sales volumes for our properties:
Year Ended December 31,
2025
2024
2023
Oil (MBbls)
38,139
29,945
24,287
Natural gas (MMcf)
236,978
183,227
130,629
NGLs (MBbls)
17,382
13,154
8,475
Total (MBoe)
95,017
73,637
54,533
Daily average (MBoe/d)
260
201
149
Total sales volume increased 21,380 MBoe during the year ended December 31, 2025 compared to the year ended December 31, 2024. The increase is primarily due to the SilverBow Merger and the Ridgemar Acquisition.
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 the geopolitical events, such as the recent events 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, actions taken by OPEC, sustained levels of inflation and increased U.S. drilling activity or otherwise. Uncertainty persists regarding OPEC’s actions, increased
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U.S. drilling, proposed tariffs, inflation and the armed conflicts in Ukraine and the Middle 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.
In order to reduce the impact of fluctuations in oil and natural gas prices on revenues, we regularly enter into derivative contracts with respect to a portion of the estimated oil, natural gas and NGL production through various transactions that fix the future prices received. We plan to continue the practice of entering into economic hedging arrangements to reduce near-term exposure to commodity prices, protect cash flow and corporate returns and maintain our liquidity.
The following table presents the percentages of our production that was economically hedged through the use of derivative contracts:
Year Ended December 31,
2025
2024
2023
Oil
63
%
67
%
65
%
Natural gas
60
%
51
%
57
%
NGLs
12
%
6
%
16
%
The following table sets forth the average NYMEX oil and natural gas prices and our average realized prices for the periods presented:
Year Ended December 31,
2025
2024
2023
Oil (Bbl):
Average NYMEX
$
64.81
$
75.72
$
77.62
Realized price (excluding derivative settlements)
62.21
71.14
72.09
Realized price (including derivative settlements) (1)
64.45
67.38
65.04
Natural Gas (Mcf):
Average NYMEX
$
3.43
$
2.27
$
2.74
Realized price (excluding derivative settlements)
2.84
1.91
2.84
Realized price (including derivative settlements) (1)
2.83
2.33
2.83
NGLs (Bbl):
Realized price (excluding derivative settlements)
$
22.47
$
24.10
$
22.76
Realized price (including derivative settlements) (1)
22.42
24.05
24.95
(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, 2023, the realized price presented above does not include $61.5 million paid for the settlement of acquired oil derivative contracts.
Results of operations:
Year ended December 31, 2025 compared to year ended December 31, 2024
Revenues
The following table provides the components of our revenues, respective average realized prices and net sales volumes for the periods indicated:
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Year Ended December 31,
2025
2024
$ Change
% Change
Revenues (in thousands):
Oil
$
2,372,726
$
2,130,418
$
242,308
11
%
Natural gas
673,540
349,858
323,682
93
%
Natural gas liquids
390,629
316,981
73,648
23
%
Midstream and other
142,887
133,662
9,225
7
%
Total revenues
$
3,579,782
$
2,930,919
$
648,863
22
%
Average realized prices, before effects of derivative settlements:
Oil ($/Bbl)
$
62.21
$
71.14
$
(8.93)
(13
%)
Natural gas ($/Mcf)
$
2.84
$
1.91
$
0.93
49
%
NGLs ($/Bbl)
$
22.47
$
24.10
$
(1.63)
(7
%)
Total ($/Boe)
$
36.17
$
37.99
$
(1.82)
(5
%)
Net sales volumes:
Oil (MBbls)
38,139
29,945
8,194
27
%
Natural gas (MMcf)
236,978
183,227
53,751
29
%
NGLs (MBbls)
17,382
13,154
4,228
32
%
Total (MBoe)
95,017
73,637
21,380
29
%
Average daily net sales volumes:
Oil (MBbls/d)
104
82
22
27
%
Natural gas (MMcf/d)
649
501
148
30
%
NGLs (MBbls/d)
48
36
12
33
%
Total (MBoe/d)
260
201
59
29
%
Oil revenue. Oil revenue increased $242.3 million, or 11%, in 2025 compared to 2024. This increase was driven by a $583.0 million increase from higher sales volumes (22 MBbl/d, or 27%), partially offset by lower realized oil prices that resulted in a decrease of $340.7 million (a decline of 13% per Bbl). The increase in sales volumes was primarily driven by the SilverBow Merger and the Ridgemar Acquisition. The decrease in realized oil prices was due to lower index prices partially offset by more favorable price differentials.
Natural gas revenue. Natural gas revenue increased $323.7 million, or 93%, in 2025 compared to 2024. This increase was driven by higher realized natural gas prices that resulted in an increase of $221.0 million (an increase of 49% per Mcf) and a $102.7 million increase from higher sales volumes (148 MMcf/d, or 30%). The increase in sales volumes was primarily due to the SilverBow Merger and the Ridgemar Acquisition. The increase in realized natural gas prices was due to higher benchmark prices.
NGL revenue. NGL revenue increased $73.6 million, or 23%, in 2025 compared to 2024. This increase was driven by a $101.8 million increase from higher sales volumes (12 MBbl/d, or 33%), partially offset by lower realized NGL prices that resulted in a decrease of $28.2 million (a decline of 7% per Bbl). The increase in sales volumes was primarily driven by the SilverBow Merger and the Ridgemar Acquisition.
Midstream and other revenue. Midstream and other revenue increased $9.2 million, or 7%, in 2025 compared to 2024, driven primarily by higher sulfur revenues, higher oil blending and marketing revenues in 2025.
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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:
Year Ended December 31,
2025
2024
$ Change
% Change
Expenses (in thousands):
Operating expense
$
1,587,632
$
1,278,055
$
309,577
24
%
Depreciation, depletion and amortization
1,166,902
949,480
217,422
23
%
Impairment expense
254,551
161,542
93,009
NM*
General and administrative expense
472,160
336,219
135,941
40
%
Other operating costs
(130,742)
(12,839)
(117,903)
918
%
Total expenses
$
3,350,503
$
2,712,457
$
638,046
24
%
Selected expenses per Boe:
Operating expense
$
16.71
$
17.36
$
(0.65)
(4)
%
Depreciation, depletion and amortization
12.28
12.89
(0.61)
(5
%)
*NM = Not meaningful.
Operating expense. Total operating expense increased $309.6 million, or 24%, in 2025 compared to 2024, driven primarily by the following factors:
(i)Lease and asset operating expenses increased $135.8 million, or 21%, in 2025 compared to 2024. Additionally, lease and asset operating expense per Boe decreased $0.50 per Boe from $8.58 per Boe to $8.08 per Boe. This $135.8 million increase was driven primarily by higher production from the SilverBow Merger and the Ridgemar Acquisition, which was more than offset on a per Boe basis with the additional acquired volumes and cost reduction measures on our legacy assets.
(ii)Gathering, processing and transportation expense increased $96.0 million, or 31%, and increased $0.05 per Boe from $4.25 per Boe to $4.30 per Boe in 2025 compared to 2024. The increase was driven primarily by the SilverBow Merger and the Ridgemar Acquisition.
(iii)Production and other taxes increased $56.8 million, or 35%, in 2025 compared to 2024 and increased $0.10 per Boe, or 5%, to $2.31 per Boe. This increase was driven primarily by higher oil and gas revenues, which increased the tax base upon which our production and other taxes are calculated.
(iv)Workover expense increased $14.2 million in 2025 compared to 2024, and decreased $0.04 per Boe from $0.82 per Boe to $0.78 per Boe. This absolute dollar increase was primarily driven by the SilverBow Merger and the Ridgemar Acquisition.
(v)Midstream and other operating expense increased $6.8 million, or 6%, in 2025 compared to 2024, primarily due to increased crude oil blending and marketing expenses, which 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 $217.4 million, or 23%, in 2025 compared to 2024, driven primarily by increased production from the SilverBow Merger and the Ridgemar Acquisition.
Impairment expense. During the years ended December 31, 2025 and 2024, we evaluated our oil and natural gas properties 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 oil and natural gas properties that were determined not to be recoverable.
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General and administrative expense. General and administrative expense ("G&A") increased $135.9 million, or 40%, in 2025 compared to 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 $55.6 million (2025 and 2024 include additional catch up expense of $146.5 million and $121.8 million, respectively, due to change in estimate) and (iii) $30.4 million higher transaction and nonrecurring related expenses.
Year Ended December 31,
2025
2024
$ Change
% Change
General and administrative expense (in thousands)
Recurring general and administrative expense
$
122,759
$
72,857
$
49,902
68
%
Transaction and nonrecurring expenses
100,325
69,881
30,444
44
%
Equity-based compensation
249,076
193,481
55,595
29
%
Total general and administrative expense
$
472,160
$
336,219
$
135,941
40
%
General and administrative expense per Boe:
Recurring general and administrative expense
$
1.29
$
0.99
$
0.30
30
%
Transaction and nonrecurring expenses
1.06
0.95
0.11
12
%
Equity-based compensation
2.62
2.63
(0.01)
—
%
Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs decreased by $117.9 million compared to 2024, primary driven by a $118.1 million higher gain on sale of assets recognized in 2025.
Interest expense. In 2025, we incurred interest expense of $298.4 million, as compared to $216.3 million in 2024, a 38% increase. The increase was primarily driven by higher average debt balances driven by the SilverBow Merger and the Ridgemar 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.
Gain (loss) on derivatives. We have entered into derivative contracts to manage our exposure to commodity price risks that impact our revenue and have derivative gains and losses related to our contingent earn-out consideration. Our gain on derivatives during 2025, changed by $417.2 million, from a comparable loss during 2024 primarily due to changes in commodity prices relative to our strike prices.
Income tax benefit (expense). For the years ended December 31, 2025 and 2024 we recognized income tax expense of $34.5 million and income tax benefit of $31.1 million, respectively, for an effective tax rate of 17.1% and 18.4%, 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 tax 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 decreased in 2025 primarily driven by our divestitures combined with timing of income allocated to our noncontrolling interests and redeemable noncontrolling interests.
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.
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The following tables present reconciliations 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:
Year Ended December 31,
2025
2024
$ Change
% Change
(in thousands, except percentages)
Net income (loss)
$
167,166
$
(137,683)
$
304,849
(221)
%
Adjustments to reconcile to Adjusted EBITDAX:
Interest expense
298,432
216,263
Loss from extinguishment of debt
29,248
59,095
Income tax expense (benefit)
34,504
(31,072)
Depreciation, depletion and amortization
1,166,902
949,480
Exploration expense
16,795
16,591
Non-cash (gain) loss on derivatives
(221,294)
78,494
Impairment expense
254,551
161,542
Non-cash equity-based compensation expense
245,468
193,481
Gain on sale of assets
(147,537)
(29,430)
Other (income) expense
5,018
(1,760)
Certain redeemable noncontrolling interest distributions made by OpCo (1)
(4,242)
(19,963)
Transaction and nonrecurring expenses (2)
137,433
82,484
Settlement of acquired derivative contracts
83,142
60,787
Adjusted EBITDAX (non-GAAP)
$
2,065,586
$
1,598,309
$
467,277
29
%
Adjustments to reconcile to Levered Free Cash Flow:
Interest expense, excluding non-cash amortization of deferred financing costs, discounts, and premiums
(283,915)
(202,886)
Loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts, and premiums
(22,360)
(14,817)
Current income tax benefit (expense)
1,152
(4,782)
Tax-related redeemable noncontrolling interest distributions made by OpCo
(1,108)
(458)
Development of oil and natural gas properties
(903,232)
(745,198)
Levered Free Cash Flow (non-GAAP)
$
856,123
$
630,168
$
225,955
36
%
(1)In our calculation of Adjusted EBITDAX and Levered Free Cash Flow, we 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 holders of redeemable noncontrolling interests in OpCo.
(2)Transaction and nonrecurring expenses of $137.4 million during the year ended December 31, 2025 were primarily related to the Vital Energy Merger and the Ridgemar Acquisition transition costs, divestiture and restructuring costs, and legal settlement costs. Transaction and nonrecurring expenses of $82.5 million for the year ended December 31, 2024 were primarily related to the SilverBow Merger, capital markets transactions and integration expenses.
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Year Ended December 31,
2025
2024
$ Change
% Change
(in thousands, except percentages)
Net cash provided by operating activities
$
1,680,156
$
1,223,086
$
457,070
37
%
Changes in operating assets and liabilities
(81,565)
49,695
Certain redeemable noncontrolling interest distributions made by OpCo (1)
(4,242)
(19,963)
Tax-related redeemable noncontrolling interest contributions (distributions) made by OpCo
(1,108)
(458)
Transaction and nonrecurring expenses (2)
137,433
82,484
Loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts, and premiums
(22,360)
(14,817)
Exploration expense
16,795
16,591
Other adjustments and operating activities
34,246
38,748
Development of oil and natural gas properties
(903,232)
(745,198)
Levered Free Cash Flow (non-GAAP)
$
856,123
$
630,168
$
225,955
36
%
(1)In our calculation of Adjusted EBITDAX and Levered Free Cash Flow, we 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 holders of redeemable noncontrolling interests in OpCo.
(2)Transaction and nonrecurring expenses of $137.4 million during the year ended December 31, 2025 were primarily related to the Vital Energy Merger and the Ridgemar Acquisition transition costs, divestiture and restructuring costs, and legal settlement costs. Transaction and nonrecurring expenses of $82.5 million for the year ended December 31, 2024 were primarily related to the SilverBow Merger, capital markets transactions and integration expenses.
Adjusted EBITDAX (non-GAAP) increased by $467.3 million or 29% in 2025, compared to 2024, driven primarily by additional production generated by the SilverBow Merger and the Ridgemar Acquisition, partially offset by lower oil pricing.
Levered Free Cash Flow (non-GAAP) increased by $226.0 million or 36% in 2025 compared to 2024, driven primarily by increased Adjusted EBITDAX of $467.3 million, partially offset by $158.0 million of increased development of oil and natural gas properties expenditures and additional interest expense, excluding non-cash amortization.
Liquidity and capital resources
Our primary sources of liquidity are cash flow from operations, proceeds from equity and debt offerings and borrowings under a senior secured reserve-based revolving credit agreement. 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 effort 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. For information regarding risks related to our derivative program, see "Part I., Item 1A. Risk Factors".
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The following table presents our cash balances and outstanding borrowings at the end of each period presented:
At December 31,
(in thousands)
2025
2024
Cash and cash equivalents
$
10,157
$
132,818
Restricted cash – current
725,702
5,490
Restricted cash – noncurrent
17,451
102,600
Long-term debt
5,524,128
3,049,255
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 subsequently described under the heading “Contractual obligations,” 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:
Year Ended December 31,
(in thousands)
2025
2024
Net cash provided by operating activities
$
1,680,156
$
1,223,086
Net cash used in investing activities
(922,688)
(1,198,299)
Net cash (used in) provided by financing activities
(245,066)
207,392
Net cash provided by operating activities. Net cash provided by operating activities for the year ended December 31, 2025 increased by $457.1 million, or 37%, compared to 2024, primarily due to higher net income after adjusting for non-cash items and working capital changes.
Net cash used in investing activities. Net cash used in investing activities for the year ended December 31, 2025 decreased by $275.6 million, or 23%, compared to 2024. Our Acquisitions of oil and gas properties on the consolidated statements of cash flows of $818.9 million in 2025 was driven primarily by the Ridgemar Acquisition and the Minerals Acquisition, while the 2024 acquisitions of $558.6 million was driven by SilverBow Merger, the Central Eagle Ford Acquisition and the Eagle Ford Minerals Acquisition. Our cash expenditures related to the Development of oil and natural gas properties on the consolidated statements of cash flows increased by $265.4 million, and we had $792.4 million higher proceeds from the sale of oil and natural gas properties.
Net cash (provided by) used in financing activities. Net cash used in financing activities for the year ended December 31, 2025 was $245.1 million, a decrease of $452.5 million, primarily due to our debt repayments in 2025 compared to our debt borrowings in 2024.
Debt agreements
Senior Notes
2034 Notes
In July 2025, we issued $600.0 million aggregate principal amount of the 2034 Notes at par. The 2034 Notes bear interest at an annual rate of 8.375%, which is payable on January 15 and July 15 of each year, and mature on January 15, 2034. The proceeds from the 2034 Notes Offering were approximately $588.1 million after deducting the initial purchasers' discount and offering expenses. We used the net proceeds to finance the consideration of the Tender Offer and the 2028 Notes Redemption and to repay a portion of our outstanding balance under our Revolving Credit Facility.
We may, at our option, redeem all or a portion of the 2034 Notes at any time on or after July 15, 2028 at certain redemption prices. We may also redeem up to 40% of the aggregate principal amount of the 2034 Notes before July 15, 2028 with an
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amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 108.375% of the principal amount of the 2034 Notes being redeemed, plus accrued and unpaid interest, if any, to, but excluding the redemption date. In addition, prior to July 15, 2028, we may redeem some or all of the 2034 Notes at a price equal to 100% of the principal amount thereof, plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but excluding the redemption date.
2033 Notes
In June 2024, we issued $750.0 million aggregate principal amount of 2033 Notes at par. In September 2024, we issued an additional $250.0 million aggregate principal amount of 2033 Notes at 101.000% of par. 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.
All issuances of the 2033 Notes are treated as a single series of securities under the indenture governing the 2033 Notes, will vote together as a single class, and have substantially identical terms, other than the issue date and the issue price.
The 2033 Notes bear interest at an annual rate of 7.375%, which is payable on January 15 and July 15 of each year, and mature on January 15, 2033. We may, at our option, redeem all or a portion of the 2033 Notes at any time on or after July 15, 2027 at certain redemption prices. We may also redeem up to 40% of the aggregate principal amount of the 2033 Notes before July 15, 2027 with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.375% of the principal amount of the 2033 Notes being redeemed, plus accrued and unpaid interest, in any, to, but excluding the redemption date, if at least 50% of the aggregate principal amount of the Notes remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. In addition, prior to July 15, 2027, we may redeem some or all of the 2033 Notes at a price equal to 100% of the principal amount thereof, plus a "make-whole" premium and accrued and unpaid interest, if any, to but excluding the redemption date.
2032 Notes
In March 2024, we issued $700.0 million aggregate principal amount of 2032 Notes at par. In December 2024, we issued an additional $400.0 million, aggregate principal amount of 2032 Notes at 100.250% of par. 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 the Tender Offer and Redemption of all of the aggregate principal amount of the 2026 Notes outstanding for $714.8 million after including extinguishment costs. We used the proceeds from the December 2024 Offering to repay the amounts outstanding under our Revolving Credit Facility.
All issuances of the 2032 Notes are treated as a single series of securities under the indenture governing the 2032 Notes, will vote together as a single class, and have substantially identical terms, other than the issue date and the issue price.
The 2032 Notes bear interest at an annual rate of 7.625%, which is payable on April 1 and October 1 of each year, and mature on April 1, 2032. We may, at our option, redeem all or a portion of the 2032 Notes at any time on or after April 1, 2027 at certain redemption prices. We may also redeem up to 40% of the aggregate principal amount of the 2032 Notes before April 1, 2027 with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.625% of the principal amount of the 2032 Notes being redeemed, plus accrued and unpaid interest, if any, to, but excluding the redemption date. In addition, prior to April 1, 2027, we may redeem some or all of the 2032 Notes at a price equal to 100% of the principal amount thereof, plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but excluding the redemption date.
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In conjunction with the Vital Energy Merger we assumed $1.0 billion aggregate principal amount of 7.875% senior notes due 2032 of Crescent Energy Finance LLC, as successor in interest to Vital (the "Vital 2032 Notes"). The Vital 2032 Notes will mature on April 15, 2032, with interest accruing at a rate of 7.875% per annum and payable semi-annually, on April 15 and October 15 of each year. We may redeem up to 35% of the aggregate principal amount of the Vital 2032 Notes before April 15, 2027 using funds in an amount not exceeding the net proceeds from one or more private or public equity offerings at a redemption price of 107.875% of the aggregate principal amount of the Vital 2032 Notes redeemed, plus accrued and unpaid interest to the date of redemption. In addition, prior to April 15, 2027, we may redeem all or a part of the Vital 2032 Notes at a redemption price equal to 100% of the principal amount, plus a “make-whole” premium as of, and accrued and unpaid interest, if any, to, the redemption date.
2030 Notes
In conjunction with the Vital Energy Merger we assumed $302.4 million aggregate principal amount of the Vital 2030 Notes. On January 2, 2026, Crescent Energy Finance LLC settled the Exchange Offers, wherein approximately $237.4 million aggregate principal amount of the Vital 2030 Notes were exchanged for approximately $237.2 million aggregate principal amount of the Crescent 2030 Notes, which tendered and accepted Vital 2030 Notes were subsequently canceled. Following the Exchange Offers, approximately $65.0 million aggregate principal amount of the Vital 2030 Notes and approximately $237.2 million of the Crescent 2030 Notes remain outstanding, which are collectively referred to as the "2030 Notes" herein. The 2030 Notes will mature on October 15, 2030, with interest accruing at a rate of 9.750% per annum and payable semi-annually, on April 15 and October 15 of each year. We may, at our option, redeem all or a portion of the 2030 Notes at any time on or after October 15, 2026 at a price equal to 104.875% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but excluding the redemption date. If, on or after October 15, 2027, we may redeem some or all of the Crescent 2030 Notes at a price equal to 102.4375% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but excluding the redemption date. In addition, on or after October 15, 2028 and thereafter, we may redeem some or all of the Crescent 2030 Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but excluding the redemption date.
2029 Notes
In conjunction with the Vital Energy Merger we assumed $298.2 million aggregate principal amount of the Vital 2029 Notes. On January 2, 2026, Crescent Energy Finance LLC settled the Exchange Offers wherein approximately $295.3 million aggregate principal amount of the Vital 2029 Notes were exchanged for approximately $294.8 million aggregate principal amount of the Crescent 2029 Notes, which tendered and accepted Vital 2029 Notes were subsequently canceled. Following the Exchange Offers, approximately $2.9 million aggregate principal amount of the Vital 2029 Notes and approximately $294.8 million of the Crescent 2029 Notes remain outstanding, which are collectively referred to as the "2029 Notes" herein (collectively with the 2028 Notes, the 2030 Notes, the Vital 2032 Notes, the 2032 Notes, the 2033 Notes and the 2034 Notes, the "Senior Notes"). The 2029 Notes will mature on July 31, 2029, with interest accruing at a rate of 7.750% per annum and payable semi-annually, on January 31 and July 31 of each year. We may, at our option, redeem all or a portion of the 2029 Notes at any time before July 31, 2026 at a price equal to 101.9375% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but excluding the redemption date. In addition, on or after July 31, 2026, we may redeem some or all of the 2029 Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but excluding the redemption date.
2028 Notes
As of December 31, 2024 we had $1.0 billion of the 2028 Notes outstanding. The 2028 Notes bear interest at an annual rate of 9.250%, which is payable on February 15 and August 15 of each year and mature on February 15, 2028. We may, at our option, redeem all or a portion of the 2028 Notes at any time before February 15, 2027 at a price equal to 102.3125% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but excluding the redemption date. In addition, on or after February 15, 2027, we may redeem some or all of the 2028 Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but excluding the redemption date.
In June 2025, we commenced the Tender Offer to purchase a portion of our outstanding 2028 Notes, pursuant to which approximately $306.1 million aggregate principal amount of 2028 Notes were validly tendered and not validly withdrawn at or prior to July 22, 2025, the final tender date. In addition to the Tender Offer, we elected to redeem an aggregate principal amount of the 2028 Notes equal to $193.9 million, at a price of 104.625% of the unpaid principal amount of the 2028 Notes, plus accrued and unpaid interest, if any, to, but excluding, July 25, 2025, the redemption date. After giving effect to the 2028 Notes Redemption and the Tender Offer, the aggregate principal amount of the 2028 Notes outstanding is $500.0 million. Combined,
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we purchased the 2028 Notes at a blended price of 104.472% of par and incurred a loss on the extinguishment of debt of approximately $29.2 million, including the write-off of associated deferred financing costs, during the year ended December 31, 2025.
The Senior Notes are our senior unsecured obligations and the Senior Notes and the related guarantees rank equally in right of payment with the borrowings under our Revolving Credit Facility and any of our other future senior indebtedness and senior to any of our future subordinated indebtedness. The Senior Notes are guaranteed on a senior unsecured basis by each of our existing and future subsidiaries that will guarantee our Revolving Credit Facility. The Senior Notes and the guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our Revolving Credit Facility) to the extent of the value of the collateral securing such indebtedness and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the Senior Notes.
The indentures governing the Senior Notes contains covenants that, among other things, limit the ability of the our restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends or distributions in respect of its equity or redeem, repurchase or retire its equity or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from any non-Guarantor restricted subsidiary to it; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.
If we experience certain kinds of changes of control accompanied by a ratings decline, holders of the Senior Notes may require us to repurchase all or a portion of their notes at certain redemption prices. The Senior Notes are not listed, and we do not intend to list the notes in the future, on any securities exchange, and currently there is no public market for the notes.
Revolving Credit Facility
We are party to a senior secured reserve-based revolving credit agreement (as amended, restated, amended and restated or otherwise modified to date, the "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. The Revolving Credit Facility matures on October 22, 2030. At December 31, 2025, we had $772.0 amount of outstanding borrowings under the Revolving Credit Facility and $16.6 million in outstanding letters of credit, our elected commitment amount was $2.0 billion, and we had $1.2 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 secured overnight financing rate ("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 December 31, 2025 is 0.375% per year. Our weighted average interest rate on loan amounts outstanding as of December 31, 2025 was 5.56% and we had no borrowings outstanding under the Revolving Credit Facility as of December 31, 2024.
The borrowing base under the Revolving Credit Facility was $3.9 billion as of December 31, 2025. The borrowing base is subject to semi-annual scheduled redeterminations on or about April 1 and October 1 of each year, as well as (i) elective borrowing base interim redeterminations at our request not more than twice during any consecutive 12-month period or the required lenders not more than once during any consecutive 12-month period and (ii) elective borrowing base interim redeterminations at our request following any acquisition of oil and natural gas properties with a purchase price in the aggregate of at least 5.0% of the then effective borrowing base. The borrowing base will be automatically reduced upon (a) the issuance of certain permitted junior lien debt and other permitted additional debt, (b) the sale or other disposition of borrowing base properties if the aggregate net present value, discounted at 9% per annum (“PV-9”) of such properties sold or disposed of is in excess of 5.0% of the borrowing base then in effect and (c) early termination or set-off of swap agreements (x) the administrative agent relied on in determining the borrowing base or (y) if the value of such swap agreements so terminated is in excess of 5.0% of the borrowing base then in effect.
The obligations under the Revolving Credit Facility remain secured by first priority liens on substantially all of our and the guarantors’ tangible and intangible assets, including without limitation, oil and natural gas properties and associated assets and equity interests owned by us and such guarantors. In connection with each redetermination of the borrowing base, we must maintain mortgages on at least 85% of the PV-9 of the oil and gas properties that constitute borrowing base properties. Our domestic direct and indirect subsidiaries are required to be guarantors under the Revolving Credit Facility, subject to certain exceptions.
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The Revolving Credit Facility contains certain covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity, commodity swap agreements, liens and other transactions without the adherence to certain financial covenants or the prior consent of our lenders. We are subject to (i) maximum consolidated total debt to consolidated EBITDAX ratio and (ii) minimum current ratio financial covenants calculated as of the last day of each fiscal quarter. The Revolving 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. At December 31, 2025, 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.
In October 2025, in connection with the borrowing base redetermination of our Revolving Credit Facility, we entered into the Thirteenth Amendment (the “Thirteenth Amendment”) to the credit agreement governing our Revolving Credit Facility. Among other things, the Thirteenth Amendment provides for (i) an automatic $1.3 billion increase in the borrowing base from $2.6 billion to $3.9 billion, effective upon the consummation Vital Energy Merger, subject to the satisfaction of certain conditions, (ii) an extension of the maturity date for any revolving loans to October 22, 2030 from April 10, 2029, (iii) a reduction in the applicable margin, so that loans under the Credit Agreement will be priced based on the SOFR plus 1.75% to 2.75% per annum, a reduction of 0.25% per annum, and (iv) an increase in the aggregate maximum credit amount under our Revolving Credit Facility from $3.0 billion to $6.0 billion. The Thirteenth Amendment maintains the aggregate elected commitments at $2.0 billion.
Minerals and Royalties Credit Facility
On February 23, 2026, pursuant to the terms of the Revolving Credit Facility, each of CMP Crescent Minerals I (Gray) LLC, CMP Legacy Co. LLC, DMA Royalty Investments LP, EIGF Minerals GP LLC, EIGF Minerals LP, Falcon Holding LP, IE Buffalo Holdings LLC, IE Buffalo Minerals LLC, Independence Minerals GP LLC, Independence Minerals Holdings LLC, Independence Minerals L.P., Mineral Acquisition Company I, L.P., Vine Royalty GP LLC, and Vine Royalty L.P. (collectively, the “Crescent Minerals Guarantors”) were released from their respective guarantees under the Revolving Credit Facility and, as a result of such release under the Revolving Credit Facility, under the applicable indentures governing Crescent Energy Finance’s Senior Notes (collectively, the “Release”).
In connection with the Release, on February 23, 2026, the Crescent Minerals Guarantors became guarantors under that certain Credit Agreement, by and among the Crescent Royalty Finance LLC, a Delaware limited liability company, as borrower (the “Crescent Minerals Borrower”), Wells Fargo Bank N.A, as administrative agent, collateral agent and a letter of credit issuer (“Wells Fargo”), and the lenders from time to time party thereto (the “Crescent Minerals and Royalties Credit Facility”). The Crescent Minerals and Royalties Credit Facility provides for a $1.0 billion aggregate maximum credit amount senior secured reserve-based revolving credit facility, with an initial aggregate elected commitment amount of $230.0 million, and an initial term loan facility with an aggregate commitment amount of $135.0 million. Revolving loans under the Crescent Minerals and Royalties Credit Facility mature on February 23, 2031 and initial term loans under the Crescent Minerals and Royalties Credit Facility mature on February 23, 2029. Each of the Crescent Minerals Guarantors are guarantors of the debt. As of February 23, 2026, we had $365.0 million of outstanding borrowings under the Crescent Minerals and Royalties Credit Facility.
Borrowings under the Crescent Minerals and Royalties 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 secured overnight financing rate (“SOFR”), plus an applicable margin or (ii) SOFR, plus an applicable margin, at the election of the Crescent Minerals Borrower. The applicable margin and fee payable for the unused revolving commitments varies based upon the Crescent Minerals Borrower’s borrowing base utilization then in effect. The weighted average interest rate on loan amounts outstanding as of February 23, 2026 was 6.612%.
The borrowing base under the Crescent Minerals and Royalties Credit Facility is $365.0 million. The borrowing base is subject to semi-annual scheduled redeterminations on or about April 1st and October 1st of each year (commencing April 1, 2027, with the first redetermination occurring on or about September 1, 2026), as well as (i) elective borrowing base interim redeterminations at the Crescent Minerals Borrower's request not more than twice during any period between consecutive scheduled redeterminations or the required lenders’ request not more than once during any period between consecutive scheduled redeterminations and (ii) elective borrowing base interim redeterminations at the Crescent Minerals Borrower’s request following any acquisition of oil and natural gas properties with proved reserves having a PV-9 (calculated at the time of acquisition) in excess of 5.0% of the then effective borrowing base. Upon the issuance of permitted junior lien debt or permitted
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additional debt, the borrowing base will be automatically reduced by 0.25 multiplied by the stated principal amount thereof. In addition, after repayment in full of the initial term loans, the required lenders have the right to adjust the borrowing base (a) upon the sale or other disposition of borrowing base properties if the aggregate PV-9 of such properties sold or disposed of (since the later of the closing date or the last redetermination date or last adjustment under this provision) is in excess of 5.0% of the borrowing base then in effect or (b) upon early termination or creation of off-setting positions in respect of swap agreements (x) upon which the lenders relied in determining the borrowing base and (y) if the Hedge PV of such terminated or off-setting positions is in excess of 5.0% of the borrowing base then in effect.
The obligations under the Crescent Minerals Credit Facility are guaranteed by the Crescent Minerals Guarantors and are secured by first priority liens on substantially all of the Crescent Minerals Borrower’s and Crescent Minerals Guarantors’ tangible and intangible assets, including without limitation, oil and natural gas properties and associated assets and equity interests owned by the Crescent Minerals Borrower and the Crescent Minerals Guarantors. In connection with each redetermination of the borrowing base, the Crescent Minerals Borrower must maintain mortgages on at least 85% of the PV-9 of the oil and gas properties that constitute borrowing base properties.
The Crescent Minerals Credit Facility contains certain covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity, commodity swap agreements, liens and other transactions without the adherence to certain financial covenants or the prior consent of Wells Fargo. The Crescent Minerals Borrower and Crescent Minerals Guarantors are subject to (i) maximum leverage ratio and (ii) current ratio financial covenants calculated as of the last day of each fiscal quarter. The Crescent Minerals 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 the Crescent Minerals Borrower and Crescent Minerals Guarantors are unable to cure such event of default, Wells Fargo will be able to accelerate maturity and exercise other rights and remedies. As of February 23, 2026, the Crescent Minerals Borrower and Crescent Minerals Guarantors were in compliance with each of the covenants under the Crescent Minerals 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 are presented as "Development of oil and natural gas properties" in investing activities on our 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 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:
Year Ended December 31,
(in thousands)
2025
2024
Total development of oil and natural gas properties
$
903,232
$
745,198
Change in accruals and other non-cash adjustments
47,803
(59,514)
Cash used in development of oil and natural gas properties
951,035
685,684
Cash used in acquisition of oil and natural gas properties, net of cash acquired
818,873
558,600
Non-cash acquisition of oil and natural gas properties
730,684
611,423
Total expenditure on acquisition and development of oil and natural gas properties
$
2,500,592
$
1,855,707
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The increase in our development of oil and natural gas properties costs in 2025 is primarily related to an increase in our operations and related to the timing of invoices. We used cash of $818.9 million in 2025 for the acquisitions of oil and natural gas properties, primarily related to the Ridgemar Acquisition and the Minerals Acquisition, as compared to $558.6 million in 2024, which primarily related to the SilverBow Merger, the Central Eagle Ford Acquisition and the Eagle Ford Minerals Acquisition. See “Notes to Consolidated Financial Statements—NOTE 3 – Acquisitions and Divestitures" in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report.
Contractual obligations
The following table presents our material contractual obligations at December 31, 2025:
(in thousands)
Due within
one year
Due after
one year
Total
Long-term debt – principal (1)
$
—
$
5,572,578
$
5,572,578
Fixed rate long-term debt – interest (2)
385,467
2,007,319
2,392,786
Derivative liabilities (3)
—
13,421
13,421
Contingent earn-out liabilities (3)
16,153
10,717
26,870
Asset retirement obligations (4)
19,544
383,057
402,601
Oil and natural gas transportation and gathering agreements (5)
181,680
626,988
808,668
Drilling commitments (6)
17,548
8,623
26,171
Manager Compensation
78,485
73,109
151,594
Electricity purchase commitments
48,630
156,073
204,703
Sand purchase commitments
17,798
2,613
20,411
Total
$
765,305
$
8,854,498
$
9,619,803
(1)Long-term debt represents our outstanding borrowings as of December 31, 2025 consisting of our Senior Notes; (maturing on February 15, 2028, July 31, 2029, October 15, 2030, April 1, 2032, April 15, 2032, January 15, 2033 and January 15, 2034) and, if any, borrowings under our Revolving Credit Facility (maturing on October 22, 2030).
(2)Excludes variable rate debt interest payments and commitment fees related to the Revolving Credit Facility.
(3)Amounts include liabilities at December 31, 2025 that are subject to change based on future market prices for underlying commodities.
(4)Amounts represent estimated discounted costs for future dismantlement and abandonment of our oil and natural gas properties. See "Notes to Consolidated Financial Statements—NOTE 9 – Asset Retirement Obligations" in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report for additional discussion of our asset retirement obligations.
(5)Amounts include payments which will become due under long-term agreements to purchase goods and services used in the normal course of business to secure transportation of our oil and natural gas production to market, as well as, pipeline, processing and storage capacity.
(6)Amounts shown represent contractual liquidated damages at December 31, 2025 for failure to drill and complete wells on certain leases.
General and Administrative Expense
Our general and administrative expense includes corporate overhead costs, professional service fees, insurance, software applications, fees for transaction expenses, expenses payable under the Management Agreement with the Manager, incentive compensation award agreements granting profits interests, restricted stock units, performance stock units and other incentive awards granted to our employees and non-employee directors.
The incentive compensation portion relates to certain equity-classified and liability-classified profits interests awards issued by our subsidiaries (collectively, “Profits Awards”). These Profits Awards contain different vesting conditions ranging from performance-based conditions that vest upon the achievement of certain return thresholds to time-based service requirements ranging from one year to four years. Compensation cost for these awards is presented within General and administrative expense on our consolidated statements of operations. As of December 31, 2025, (i) unrecognized compensation cost related to unvested equity-classified profits interest awards was $1.5 million, and (ii) we carried $2.4 million in Other long term liabilities on the consolidated balance sheet and had no unrecognized compensation related to unvested liability-classified profits interest awards. Actual amounts paid towards equity-classified profits interests awards in the future will be shown as distributions to
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non-controlling interests in our consolidated financial statements, and may differ from the amounts shown for unrecognized compensation cost related to unvested equity-classified profits interest awards.
For additional information, see "Notes to Consolidated Financial Statements—NOTE 13 – Equity-Based Compensation Awards" in "Part II., Item 8. Financial Statements and Supplementary Data" of this 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, applicable law and the terms of our existing debt documents, including the indentures governing the Senior Notes.
We paid cash dividends totaling $0.48 per share of our Class A Common Stock to shareholders during the year ended December 31, 2025.
On February 25, 2026, the Board 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 fourth quarter of 2025. The quarterly dividend is payable on March 25, 2026 to shareholders of record as of the close of business on March 11, 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. In light of current economic conditions, management will evaluate any future increases in cash dividend on a quarterly basis.
Stock Repurchase Program
Our Board authorized a stock repurchase program in March 2024 with an approved limit of $150.0 million and a two-year term of which $86.0 million of authorization remained as of December 31, 2025. In February 2026 our Board extended the stock repurchase program indefinitely and increased the approved limit to $400.0 million. We have $336.0 million of repurchase authorization remaining under such program as of February 25, 2026. Repurchases pursuant to such program may be made from time to time in the open market, in a privately negotiated transaction, through purchases made in accordance with the Rule 10b5-1 of the Exchange Act or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be modified, suspended or discontinued at any time, and does not obligate us to repurchase any dollar amount or number of securities.
The IRA 2022 provides for, among other things, the imposition of a 1% non-deductible U.S. federal excise tax on the fair market value of any stock repurchased by a publicly traded domestic corporation during any taxable year, with the fair market value of such repurchased stock reduced by the fair market value of certain stock issued by such corporation during such taxable year (such exercise tax, the "Stock Buyback Tax"). In the past, there have been proposals to increase the amount of the Stock Buyback Tax from 1% to 4%; however, it is unclear whether such a change in the amount of the excise tax will be enacted and, if enacted, how soon any such change could take effect. The Stock Buyback Tax first applied to our stock repurchase program in the year ended December 31, 2023, and will continue to apply in subsequent taxable years.
Critical accounting estimates
Our significant accounting policies are described in "Notes to Consolidated Financial Statements—NOTE 2 – Summary of Significant Accounting Policies" in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report. The Company's consolidated financial statements are prepared in accordance with GAAP. The preparation of consolidated financial statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. The following is a discussion of the accounting policies, estimates and judgments that management believes are most significant in the application of GAAP used in the preparation of our consolidated financial statements. These accounting policies, among others, may involve a high degree of complexity and judgment on the part of management. Further, these estimates and other factors, including those outside of our control could have significant adverse impact to our financial condition, results of operations and cash flows.
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Crude oil, natural gas and NGL reserves
One of our most significant estimates is of proved crude oil, natural gas and NGL reserves. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. Our crude oil and natural gas reserves are based on a combination of proved reserves and risk-weighted probable reserves and require significant judgment. Technologies used in our reserves estimation include decline curve analysis, statistical analysis of production performance, pressure and rate transient analysis, pressure gradient analysis, reservoir simulation and volumetric analysis. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. In addition, periodic revisions of our estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, crude oil and natural gas prices, changes in costs, capital funding and drilling plans (including our five-year development plan), technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates often differ from the quantities of crude oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions.
When determining the December 31, 2025 proved reserves for each property, the benchmark prices issued by the SEC were adjusted using price differentials that account for property-specific quality and location differences. If the future average crude oil prices are below the average prices used to determine proved reserves at December 31, 2025, it could have an adverse effect on our estimates of proved reserve volumes and the value of our business. It is difficult to estimate the magnitude of any potential price change and the effect on proved reserves, due to numerous factors (including future crude oil price and performance revisions). For further discussion of risks associated with our estimation of proved reserves, see "Part I., Item 1A. Risk Factors."
Estimates of proved reserves are key components of our most significant financial estimates including the computation of depreciation, depletion and amortization ("DD&A") and impairment of proved oil and natural gas properties.
Oil and natural gas properties
Oil and natural gas producing activities are accounted for under the successful efforts method of accounting. See "Notes to Consolidated Financial Statements—NOTE 2 – Summary of Significant Accounting Policies" in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report for further discussion of the accounting policies applicable to the successful efforts method of accounting.
The successful efforts method inherently relies on the estimation of proved crude oil, natural gas and NGL reserves. The amount of estimated proved reserve volumes affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depreciated, depleted or amortized into net income and the presentation of supplemental information on oil and gas producing activities. In addition, the expected future cash flows to be generated by producing properties used for testing impairment, also in part, rely on estimates of quantities of net reserves.
Depreciation, depletion and amortization
DD&A of oil and natural gas producing properties is determined on a field-by-field basis using the units-of-production method. During the years ended December 31, 2025, 2024, and 2023, we recognized DD&A expense of $1,166.9 million, $949.5 million, and $675.8 million, respectively.
While revisions of previous reserve estimates have not historically been significant to the depreciation and depletion rates, any reduction in proved reserves, could result in an acceleration of future DD&A expense. Holding all other factors constant, if proved reserves are revised downward, the rate at which we record DD&A expense would increase, reducing net income. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense would decrease. However, a sensitivity analysis is not practicable, given the numerous assumptions required to calculate proved reserves. In addition, any unfavorable adjustments to some of the above listed assumptions (e.g. commodity prices) would likely be offset by favorable adjustments in other assumptions (e.g. lower costs) as we have historically seen in our industry.
Impairment of oil and natural gas properties
Proved and unproved oil and natural gas properties that are classified as held and used are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. When a triggering event is identified, we compare the carrying amount of our oil and natural gas properties to the estimated undiscounted cash flows our oil and natural gas properties will generate to determine if the carrying amount is recoverable. If
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the carrying amount exceeds the estimated undiscounted cash flows, we will write-down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include:
•Estimates of oil and natural gas reserves and expected timing of production. Our oil and natural gas reserves are based on a combination of proved reserves and risk-weighted probable reserves and require significant judgment. Reserve engineering is a subjective process, which requires assumptions associated with the underground accumulations of oil and natural gas, development costs, future commodity prices and the future regulatory and political environment. Any significant variance in these assumptions could materially affect the estimated quantity and value of the reserves, which would affect the fair value of our oil and natural gas properties. The estimates of our reserves help to inform our expectation of future oil and natural gas production, which will likely vary from our actual production.
•Future commodity prices, which are based on publicly available forward commodity prices for a period of time and then escalated thereafter. A decrease in estimated future commodity prices will decrease the fair value of our oil and natural gas properties.
•Future capital requirements, which are based on our internal forecasts and supported by the underlying cash flows generated from our oil and natural gas assets.
•Discount rate commensurate with the risk associated with realizing projected cash flows, which is based on a variety of factors, including market and economic conditions, as well as operational and regulatory risk.
During the years ended December 31, 2024, and 2023, we determined that there were triggering events requiring an evaluation of whether the carrying value of our oil and natural gas properties was recoverable. Following an assessment of our oil and natural gas properties, during the years ended December 31, 2024, and 2023, we recorded impairment expense of $161.5 million and $149.6 million, respectively.
Proved and unproved oil and natural gas properties are also evaluated for impairment when they become classified as held for sale. We write down the carrying value of such oil and natural gas properties to the estimated transaction price less cost to sell. During the year ended December 31, 2025, we performed an assessment of the fair value of the oil and natural gas properties classified as held for sale, and subsequently determined the transaction price less cost of sell exceeded the carrying value of certain oil and natural gas properties, which resulted in impairment expense of $233.7 million.
Properties acquired in business combinations
When sufficient market data is not available, we determine the fair values of proved and unproved oil and natural gas properties acquired in transactions accounted for as business combinations by preparing estimates of cash flows from the production of crude oil, natural gas and NGL reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimates future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved reserves, future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the business combination. When estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. For other assets and liabilities acquired in business combinations, we use a combination of available cost and market data and/or estimated cash flows to determine the fair values.
Significant reductions in the proved reserves used to determine the fair value of the acquired properties could result in future impairments of the properties. See the discussion above under "Depreciation, depletion and amortization" on the practicability of a sensitivity analysis due to changes in our fair value calculations.
Income taxes
Crescent is a holding company and its sole material assets is OpCo Units. OpCo is a partnership and is generally not subject to U.S. federal and certain state taxes. Crescent is subject to U.S. federal income and certain state tax on its allocable share of any taxable income of OpCo. Following the 2025 Class A Redemption and the Corporate Simplification, the Company is the sole holder of all outstanding OpCo Units.
Historically, our effective tax rate has 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 tax 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 year ended December 31, 2025 increased primarily due to our increased ownership of OpCo in 2025.
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The amount of income taxes recorded by the Company requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. We routinely assess the realizability of our deferred tax assets and reduce such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. We routinely assess potential uncertain tax positions and, if required, establish accruals for such amounts. The accruals for deferred tax assets and liabilities, including deferred state income tax assets and liabilities, are subject to significant judgment and are reviewed and adjusted routinely based on changes in facts and circumstances. Although we consider our tax accruals adequate, material changes in these accruals may occur in the future, based on the impact of tax audits, changes in legislation and resolution of pending or future tax matters. Refer to "Notes to Consolidated Financial Statements—NOTE 11 – Income Taxes" in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report for more information.
New and revised accounting standards
See “Notes to Consolidated Financial Statements—NOTE 2 – Summary of Significant Accounting Policies” in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report.
Non-GAAP financial measures
Our “Management’s Discussion and Analysis of Financial Condition and Results of Operations” 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 make our investment decisions. We believe that the presentation of these non-GAAP 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.
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 subtract certain redeemable noncontrolling interest distributions made by OpCo and settlement of acquired derivative contracts. We include “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.
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.
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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 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.