SM Energy Co
For the period ended Dec 31, 2025. Filed Feb 26, 2026.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Feb 26, 2026
SM$29.92+1.0%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-02-20.
0000893538-25-000008
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsOverview of the CompanyFinancial Results of Operations and Additional Comparative DataComparison of Financial Results and Trends Between 2024 and 2023, and Between 2023 and 2022Overview of Liquidity and Capital ResourcesCritical Accounting EstimatesAccounting MattersEnvironmentalNon-GAAP Financial MeasuresCurrent report: 10-K
Period ended 2025-12-31; filed 2026-02-26.
0000893538-26-000032
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsOverview of the CompanyFinancial Results of Operations and Additional Comparative DataComparison of Financial Results and Trends Between 2025 and 2024Overview of Liquidity and Capital ResourcesCritical Accounting EstimatesAccounting MattersEnvironmentalNon-GAAP Financial MeasuresThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 163 previous paragraphs and 164 current paragraphs.
71 unchanged; 68 reworded; 20 added; 21 removed; 3 previous and 5 current paragraphs rearranged.
Tables are not compared: 25 previous and 23 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (20)
Current report
On November 2, 2025, we entered into the Merger Agreement with Civitas. On January 27, 2026, our stockholders voted in favor of both proposals necessary to complete the Civitas Merger, which included approval of (i) the issuance of shares of SM Energy common stock to Civitas stockholders as contemplated by the Merger Agreement, and (ii) an amendment of our Restated Certificate of Incorporation to increase the number of authorized shares of our common stock from 200 million shares to 400 million shares.
Current report
On January 30, 2026, we completed the Civitas Merger in accordance with the terms of the Merger Agreement. Civitas was an independent exploration and production company focused on the acquisition, development, and production of crude oil and associated liquids-rich natural gas in the DJ Basin in Colorado and the Permian Basin in Texas and New Mexico. We believe that the Merger will create a premier portfolio across the highest-return U.S. shale basins, driving significant free cash flow, enhancing stockholder value, and enabling the realization of significant operational and cost efficiencies.
Current report
Under the terms of the Merger Agreement, subject to certain exceptions, each share of Civitas common stock was converted into the right to receive 1.45 shares of SM Energy common stock, with cash paid in lieu of fractional shares. On January 30, 2026, we issued approximately 124 million shares to holders of Civitas common stock, representing 52 percent of the outstanding shares of SM Energy’s common stock upon the closing of the Merger. Based on the closing price of SM Energy common stock on January 30, 2026, the total stock consideration was valued at$2.4 billion.
Current report
Refer to Note 17 – Mergers, Acquisitions, and Divestitures in Part II, Item 8 of this report for additional discussion.
Current report
On February 17, 2026, we entered into the PSA with Caturus to sell certain of our South Texas assets for a Purchase Price of $950 million, subject to certain customary purchase price adjustments set forth in the PSA. This Transaction is expected to advance our deleveraging goals and position us to substantially achieve our commitment to complete at least $1.0 billion of divestitures within one year following the closing of the Civitas Merger. Refer to Note 17 – Mergers, Acquisitions, and Divestitures in Part II, Item 8 for additional discussion and the definitions of Purchase Price and Transaction.
Current report
Our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to domestic energy security and prosperity, and having a positive impact in the communities where we live and work. We are a premier operator of top-tier assets in the Midland Basin, South Texas, and the Uinta Basin, utilizing state-of-the-art digital technology, data analytics, and AI in our operations, and continually seeking innovative ideas to help us optimize capital efficiency and well performance, while reducing our impact on shared natural resources and operating in an efficient, safe, and responsible manner.
Current report
Historically, tariffs have led to increased costs for products exchanged in international trade, and have heightened global political tensions. Recent U.S. government policies, including new and higher tariffs on imported goods, have increased economic uncertainty. These tariffs, along with retaliatory tariffs from other countries, could lead to reduced trade resulting from increased costs for imported goods and decreased demand for U.S. exports, as well as reduced investment and technological exchange between major economies. These outcomes could negatively impact global economic conditions, financial market stability, and commodity prices. Volatility in political, trade, regulatory, and economic conditions could have a material adverse effect on our financial condition or results of operations. We are unable to reasonably estimate the period of time that these market conditions will exist or the extent to which they will impact our business, results of operations, and financial condition.
Current report
Continuing volatility in political, trade, regulatory and economic conditions could impact supply and demand fundamentals, and any related declines in oil, gas, and NGL prices could lead to proved and unproved property impairments in the future. Future impairments of proved and unproved properties are difficult to predict, especially in a volatile price environment.
Current report
•We completed the integration of the Uinta Basin assets into our portfolio. Refer to Note 17 – Mergers, Acquisitions, and Divestitures in Part II, Item 8 of this report for additional discussion of the Uinta Basin Acquisition.
Current report
•Strong operating cash flow enabled us to reduce debt through $69 million in net repayments on our revolving credit facility, increase cash on hand to $368 million, and return capital to stockholders. We repurchased and subsequently retired 444,705 shares of our common stock at a cost of $12 million, excluding excise taxes, commissions, and fees, and paid $92 million in dividends.
Current report
Financial and Operational Results. Oil, gas, and NGL production revenue increased 17 percent to $3.1 billion for the year ended December 31, 2025, compared with $2.7 billion for 2024. This increase was primarily driven by a 21 percent increase in average net daily equivalent production to 206.8 MBOE, reflecting a full year of production from our Uinta Basin assets and continued strong well performance, partially offset by a three percent decrease in total realized price per BOE due to lower oil and NGL benchmark commodity prices. Oil, gas, and NGL production expense on a per BOE basis increased 15 percent to $11.72 per BOE for the year ended December 31, 2025, compared with 2024.
Current report
(2) The South Texas adjustments relate to previously drilled wells that we no longer intend to complete.
Current report
(3) The Uinta Basin adjustment relates to the acquisition of additional working interest in existing drilled but not completed wells.
Current report
The Civitas Merger, which closed on January 30, 2026, is expected to materially affect our future operating and financial results. The addition of Civitas’ assets and operations is expected to increase production volumes and revenues and to impact oil, gas, and NGL production expense, general and administrative expense, and other expense categories. The magnitude and timing of these impacts will depend, in part, on integration activities, operating performance, commodity prices, and other factors and may not be directly comparable to the Company’s historical results. Unless otherwise noted, the discussion below reflects the results of our legacy operations and historical trends prior to the Merger.
Current report
Net derivative gain
Current report
Our effective tax rate is impacted by changes in revenue affecting the apportionment of taxable income to states with higher statutory tax rates and proportional effects of net income on permanent items between periods and states. Our effective tax rate increased during 2025, primarily resulting from the impact of state income taxes and the decoupling of state income tax calculations from certain OBBBA provisions, partially offset by the Company’s increasing research and development (“R&D”) activities in new basins and additional credit claims. The increase also reflects the impact of excess tax deficiencies from stock-based compensation awards.
Current report
The effects of changes in tax laws are recognized in the period of enactment. On July 4, 2025, the OBBBA was enacted into law and includes, among other things, tax reform provisions that amend, eliminate, and extend tax rules under the Inflation Reduction Act and Tax Cuts and Jobs Act. During 2025, we recorded the impact of the OBBBA, which resulted in a decrease to our current portion of income tax expense. This change reflects the impacts of the reinstatement of 100 percent bonus depreciation on tangible assets; the immediate expensing of qualified R&D expenditures and the expensing of unamortized, previously capitalized, prior year qualified R&D expenditures; and a less restrictive limitation on the business interest expense deduction. Additionally, the OBBBA allows for the deduction of intangible drilling costs from Adjusted Financial Statement Income (“AFSI”) when determining whether a company is subject to and liable for the Corporate Alternative Minimum Tax (“CAMT”). As a result, we do not expect to become subject to or liable for the CAMT for the foreseeable future, notwithstanding other factors that may impact our AFSI.
Removed paragraphs (21)
Previous report
•We expanded our operations into Utah upon the completion of the Uinta Basin Acquisition during the fourth quarter of 2024. Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for additional discussion and the definition of the Uinta Basin Acquisition.
Previous report
•We issued a combined $1.5 billion of aggregate principal amount of our 2029 Senior Notes and 2032 Senior Notes and redeemed the remaining $349.1 million aggregate principal amount outstanding of our 2025 Senior Notes. Refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion.
Previous report
•Our Board of Directors approved an increase to our fixed dividend to $0.80 per share annually, to be paid in quarterly increments of $0.20 per share, which commenced in the fourth quarter of 2024. We paid a net cash dividend of $0.74 per share, an increase from $0.60 per share paid during 2023. Refer to Note 3 – Equity in Part II, Item 8 of this report for additional discussion.
Previous report
•During the first half of 2024, we repurchased and subsequently retired 1.8 million shares of our common stock at a cost of $84.0 million, excluding excise taxes, commissions, and fees. In June 2024, our Board of Directors re-authorized our existing Stock Repurchase Program, and as of December 31, 2024, $500.0 million remained available under the Stock Repurchase Program for repurchases of our common stock through December 31, 2027. Refer to Note 3 – Equity in Part II, Item 8 of this report for additional discussion.
Previous report
Financial and Operational Results. Average net daily equivalent production for the year ended December 31, 2024, increased 12 percent to 170.5 MBOE, compared with 152.0 MBOE for 2023, as a result of strong well performance, an increased number of completions, and production from our Uinta Basin assets during the fourth quarter of 2024. The increase primarily consisted of increases of seven percent and six percent from our Midland Basin and South Texas assets, respectively, and 9.1 MBOE of production from our Uinta Basin assets.
Previous report
Realized prices for oil and gas decreased two percent and 27 percent, respectively, for the year ended December 31, 2024, compared with 2023, as a result of decreases in oil and gas benchmark commodity prices. Realized price for NGLs remained flat for the year ended December 31, 2024, compared with 2023. Total realized price per BOE remained flat for the year ended December 31, 2024, compared with 2023, primarily driven by a 24 percent increase in oil production, offset by decreases in oil and gas benchmark commodity prices. Oil, gas, and NGL production revenue increased 13 percent to $2.7 billion for the year ended December 31, 2024, compared with $2.4 billion for 2023, primarily as a result of the timing of well completions, strong well performance, and production from our Uinta Basin assets during the fourth quarter of 2024. Oil, gas, and NGL production expense of $10.21 per BOE for the year ended December 31, 2024, remained flat, compared with 2023.
Previous report
(2) We acquired these drilled but not completed wells as part of the Uinta Basin Acquisition on October 1, 2024. All drilling and completion activity presented in the table above for the Uinta Basin occurred during the fourth quarter of 2024. Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for additional discussion and the definition of the Uinta Basin Acquisition.
Previous report
Comparison of Financial Results and Trends Between 2024 and 2023 and Between 2023 and 2022
Previous report
Refer to Comparison of Financial Results and Trends Between 2023 and 2022 and Between 2022 and 2021 in Management’s Discussion and Analysis of Financial Condition and Results of Operationsin Part II, Item 7 of our 2023 Annual Report on Form 10-K, filed with the SEC on February 22, 2024, for a detailed discussion of certain comparisons of our financial results and trends for the year ended December 31, 2023, compared with the year ended December 31, 2022. Refer to Comparison of Financial Results and Trends Between 2022 and 2021 and Between 2021 and 2020 in Management’s Discussion and Analysis of Financial Condition and Results of Operationsin Part II, Item 7 of our 2022 Annual Report on Form 10-K, filed with the SEC on February 23, 2023, for a detailed discussion of certain comparisons of our financial results and trends for the year ended December 31, 2022, compared with the year ended December 31, 2021.
Previous report
Average net daily equivalent production volumes for the year ended December 31, 2023, increased five percent compared with 2022, comprised of a 20 percent increase from our South Texas assets, partially offset by a seven percent decrease from our Midland Basin assets. As a result of decreases in benchmark commodity prices, realized prices for oil, gas, and NGLs decreased 19 percent, 61 percent, and 35 percent, respectively, resulting in a 29 percent decrease in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense for the year ended December 31, 2023, decreased nine percent compared with 2022, primarily driven by decreases in production taxes and transportation costs, partially offset by an increase in LOE.
Previous report
Net derivative (gain) loss
Previous report
Interest income
Previous report
Interest income increased for the year ended December 31, 2024, compared with 2023, primarily due to maintaining a higher average balance of our interest-bearing cash and cash equivalents as a result of the issuance of our 2029 Senior Notes and 2032 Senior Notes during the third quarter of 2024 resulting in excess cash prior to the Closing Date of the Uinta Basin Acquisition. Refer to Note 17 – Acquisitionsin Part II, Item 8 of this report for additional discussion and definitions.
Previous report
Loss on extinguishment of debt
Previous report
The redemption of our 2025 Senior Secured Notes during 2022 resulted in a net loss on extinguishment of debt of $67.2 million, which included $33.5 million of premium paid, $26.3 million of accelerated expense recognition of the unamortized debt discount, and $7.4 million of accelerated expense recognition of the unamortized deferred financing costs. Refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion and the definition of 2025 Senior Secured Notes.
Previous report
Our effective tax rate in 2023 benefited from credits claimed as the result of the completion of a multi-year research and development (“R&D”) credit study. Excess tax deficiencies from stock-based compensation awards offset limits on expensing of certain covered individual’s compensation, net apportionment changes and other permanent expense items reduced the rate for each period presented. We benefited from the release of a valuation allowance on certain deferred tax assets in 2022.
Previous report
Enactment of changes to federal income tax laws, including changes in the corporate tax rate, could have a material effect on our current tax expense, tax receivable, and deferred tax liabilities. Effective for tax years beginning after December 31, 2022, the IRA provides for a 15 percent corporate alternative minimum tax (“CAMT”) on corporations with average adjusted financial statement income over $1.0 billion for any three-year period preceding the tax year. While the final proposed regulations regarding the CAMT may impact our calculation, as of the filing of this report we do not anticipate that we will become subject to the CAMT in 2025. Refer to Overview of Liquidity and Capital Resources below and to the Risk Factors section in Part 1, Item 1A of this report.
Previous report
Net cash used in investing activities increased for the year ended December 31, 2023, compared with 2022, as a result of a $109.5 million increase in capital expenditures and $109.9 million of cash paid to acquire proved and unproved oil and gas properties in the Midland Basin, including the acquisition of additional working interests in certain wells.
Previous report
Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for additional discussion of acquisition activity and the definition of the Uinta Basin Acquisition.
Previous report
Net cash used in financing activities during the year ended December 31, 2022, related to $480.2 million of cash paid, including premium, to redeem our 2025 Senior Secured Notes, and $104.8 million to redeem our 2024 Senior Notes. Additionally, we paid $57.2 million, including commission and fees, to repurchase and subsequently retire 1.4 million shares of our common stock under the Stock Repurchase Program, $25.1 million for the net share settlement of employee stock awards, and paid $19.6 million of dividends to our stockholders.
Previous report
(1)For the year ended December 31, 2023, performance revisions consisted of positive revisions of 65.3 MMBOE resulting from changes to decline curve estimates based on reservoir engineering analysis and negative revisions of 28.0 MMBOE related to well performance.
Reworded paragraphs (68)
Previous wording
The following discussion includes forward-looking statements. Refer to the Cautionary Information about Forward-Looking Statements section of this report for important information about these types of statements.
Current wording
The following discussion includes forward-looking statements. Refer to the Cautionary Information about Forward-Looking Statements section of this report for important information about these types of statements. For discussion related to changes in financial condition and results of operations for the year ended December 31, 2024, compared with the year ended December 31, 2023, refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 20, 2025.
Previous wording
Our asset portfolio is comprised of high-quality assets in the Midland Basin of West Texas, the Maverick Basin of South Texas, and the Uinta Basin of northeastern Utah, which we believe are capable of generating strong returns in the current macroeconomic environment and provide resilience to commodity price risk and volatility. We seek to maximize returns and increase the value of our top-tier assets through disciplined capital spending, strategic acquisitions, including the Uinta Basin Acquisition, and continued development and optimization of our existing assets. We believe that our high-quality assets facilitate a sustainable approach to prioritizing operational execution, maintaining a strong balance sheet, generating cash flows, returning capital to stockholders, and maintaining financial flexibility. Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for additional discussion and for the definition of the Uinta Basin Acquisition.
Current wording
Following the closing of the Civitas Merger, our asset portfolio consists of high-quality assets in the Midland Basin and Delaware Basin, both of which are part of the larger Permian Basin of Texas and New Mexico, the Maverick Basin of South Texas, the Uinta Basin of northeast Utah, and the DJ Basin of northeast Colorado. We believe our assets are capable of generating strong returns in the current macroeconomic environment and provide resilience to commodity price risk and volatility. Through disciplined capital spending, strategic acquisitions and divestitures, and continued development and optimization, we seek to maximize returns and increase the value of our top-tier asset base while maintaining financial flexibility and a sustainable approach to long-term value creation.
Previous wording
Our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to domestic energy security and prosperity, and having a positive impact in the communities where we live and work. Our long-term vision and strategy is to sustainably grow value for all of our stakeholders as a premier operator of top-tier assets by maintaining and optimizing our high-quality asset portfolio, generating cash flows, and maintaining a strong balance sheet. Our team executes this strategy by prioritizing safety, technological innovation, and stewardship of natural resources, all of which are integral to our corporate culture. Our near-term goals include focusing on operational execution and successfully integrating the Uinta Basin assets; generating cash flows that enable us to continue returning value to stockholders through fixed dividend payments, debt repayments, and our Stock Repurchase Program; and expanding our portfolio of top-tier economic drilling inventory through acquisition and exploration.
Current wording
Our long-term vision and strategy are focused on sustainably growing value for all of our stakeholders by deploying our technical excellence and exceptional execution to improve and optimize our high-quality asset portfolio, generate cash flows, and maintain a disciplined, strong balance sheet. Our team executes our strategy by prioritizing safety, technological innovation, and stewardship of natural resources, which are foundational to our corporate culture. Our near-term strategic focus is the successful integration of Civitas following the closing of the Merger on January 30, 2026. Integration is centered on maintaining safe operations, delivering consistent operational execution, and continuing to generate cash flows that enable us to return value to stockholders through fixed dividend payments, debt reduction, and share repurchases. Refer to Outlookfor discussion of our 2026 capital program.
Previous wording
We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; building and maintaining partnerships with our stakeholders by investing in and connecting with the communities where we live and work; and transparency in reporting our progress in these areas. The Environmental, Social and Governance Committee of our Board of Directors oversees, among other things, the effectiveness of our ESG policies, programs and initiatives, monitors and responds to emerging trends, issues, and associated risks, and, together with management, reports to our Board of Directors regarding such matters. Further demonstrating our commitment to sustainable operations and environmental stewardship, compensation for our executives and eligible employees under our long-term incentive plan, and compensation for all employees under our short-term incentive plan is calculated based on, in part, certain Company-wide, performance-based metrics that include key financial, operational, environmental, health, and safety measures. Refer to our Definitive Proxy Statement on Schedule 14A for the 2025 annual meeting of stockholders to be filed within 120 days from December 31, 2024, for additional discussion of our compensation programs.
Current wording
We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; building and maintaining partnerships with our stakeholders by investing in and connecting with the communities where we live and work; and transparency in reporting our progress in these areas. The Governance and Sustainability Committee of our Board of Directors oversees, among other things, the effectiveness of our sustainability policies, programs and initiatives, monitors and responds to emerging trends, issues, and associated risks, and, together with management, reports to our Board of Directors regarding such matters. Further demonstrating our commitment to sustainable operations and environmental stewardship, compensation for our executives and employees under certain aspects of our compensation plans is calculated based on Company-wide performance metrics that include key financial, operational, environmental, health, and safety measures. Refer to our Definitive Proxy Statement on Schedule 14A for the 2026 annual meeting of stockholders to be filed within 120 days from December 31, 2025, for additional discussion of our compensation program.
Previous wording
We are affected by global commodity and financial markets that remain subject to heightened levels of uncertainty and volatility. Key factors contributing to market fluctuations include ongoing oil production curtailment agreements among OPEC+, fluctuations in oil and gas demand from China, War and Geopolitical Instability, United States Federal Reserve monetary policy, shipping channel constraints and disruptions, tariffs or trade restrictions, and changes in global oil inventory in storage. These factors have driven commodity price volatility, contributed to instances of supply chain disruptions and fluctuations in interest rates, and could have further industry-specific impacts that may require us to adjust our business plan. Future impacts of these and other events on commodity and financial markets are inherently unpredictable. Despite continuing uncertainty, we expect to maximize the value of our high-quality asset base and sustain strong operational performance and financial stability. We remain focused on generating cash flows to enable us to return capital to stockholders and reduce our debt.
Current wording
As global commodities, the prices of oil, gas, and NGLs, as well as broader financial markets, remain subject to heightened uncertainty and volatility. Market conditions are influenced by factors including real or perceived geopolitical risks, War and Geopolitical Instability, OPEC+ production decisions, fluctuations in global supply and demand (including demand from China), U.S. Federal Reserve monetary policy, movements in the strength of the U.S. dollar, shipping channel constraints and disruptions, tariffs or trade restrictions, and changes in global oil inventory in storage. These factors have resulted in commodity price volatility, contributed to instances of supply chain disruptions, inflation, and interest rate fluctuations, and could have further industry-specific impacts that may require us to adjust our business plan. The timing and magnitude of future effects are inherently unpredictable.
Previous wording
We expect our total 2025 capital program to be approximately $1.3 billion, excluding acquisitions, which we expect to fund with cash flows from operations, with any remaining cash needs being funded by borrowings under our revolving credit facility. We plan to focus our 2025 capital program on highly economic oil development projects in our Midland Basin, South Texas, and Uinta Basin assets. Refer to Outlookin Part I, Items 1 and 2 of this report for additional discussion.
Current wording
We expect our total 2026 capital program to be approximately $2.65 billion to $2.85 billion, excluding acquisitions, which we expect to fund with cash flows from operations, with any remaining cash needs being funded by borrowings under our revolving credit facility. We plan to focus our 2026 capital program on highly economic oil development projects in our Midland Basin, South Texas, Uinta Basin, and DJ Basin assets. Refer to Outlookin Part I, Items 1 and 2 of this report for additional discussion.
Previous wording
We recorded net derivative gains of $50.0 million and $68.2 million for the years ended December 31, 2024, and 2023, respectively. These amounts include net derivative settlement gains of $68.7 million and $26.9 million for the years ended December 31, 2024, and 2023, respectively.
Current wording
We recorded net derivative gains of $178 million and $50 million for the years ended December 31, 2025, and 2024, respectively. These amounts include net derivative settlement gains of $132 million and $69 million for the years ended December 31, 2025, and 2024, respectively.
Previous wording
•Net cash provided by operating activities of $1.8 billion, compared with $1.6 billion for 2023.
Current wording
•Net cash provided by operating activities of $2.0 billion, compared with $1.8 billion for 2024.
Previous wording
•Net income of $770.3 million, or $6.67 per diluted share, compared with net income of $817.9 million, or $6.86 per diluted share for 2023.
Current wording
•Net income of $648 million, or $5.64 per diluted share, compared with net income of $770 million, or $6.67 per diluted share for 2024.
Previous wording
•Adjusted EBITDAX, a non-GAAP financial measure, of $2.0 billion, compared with $1.7 billion for 2023. Refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to net income and net cash provided by operating activities.
Current wording
•Adjusted EBITDAX, a non-GAAP financial measure, of $2.3 billion, compared with $2.0 billion for 2024. Refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to net income and net cash provided by operating activities.
Previous wording
•A 12 percent increase in total estimated net proved reserves as of December 31, 2024, from December 31, 2023, to 678.3 MMBOE, of which, 62 percent were liquids (oil and NGLs) and 60 percent were proved developed reserves. The increase primarily consisted of the acquisition of 103.2 MMBOE of estimated net proved reserves in the Uinta Basin and revisions of previous estimates of 74.7 MMBOE related to infill reserves in both our South Texas and Midland Basin programs, partially offset by 62.4 MMBOE of production during 2024 and the removal of 30.5 MMBOE of certain net proved undeveloped reserves cases that are no longer expected to be developed within the five-year period from initial booking, as a result of the reallocation of capital to include our Uinta Basin assets. Our proved reserve life index remained flat at 10.9 years as of December 31, 2024, and 2023. Refer to Reserves in Part I, Items 1 and 2 of this report for additional discussion. The standardized measure of discounted future net cash flows was $7.3 billion as of December 31, 2024, compared with $6.3 billion as of December 31, 2023, which was an increase of 16 percent year-over-year primarily driven by the Uinta Basin Acquisition, partially offset by decreases in oil and gas benchmark commodity prices during 2024. Refer to Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion.
Current wording
•Estimated net proved reserves decreased slightly to 673.0 MMBOE as of December 31, 2025 from 678.3 MMBOE as of December 31, 2024. As of December 31, 2025, 60 percent of our net proved reserves were liquids (oil and NGLs), and 61 percent were proved developed reserves. The decrease primarily related to 75.5 MMBOE produced in 2025, the removal of 40.7 MMBOE of certain net proved undeveloped reserves that are no longer expected to be developed within the five-year period from initial booking resulting from testing and delineation efforts, and 15.5 MMBOE of net performance and price revisions. The decreases were mostly offset by revisions of previous estimates of 87.0 MMBOE related to infill reserves, primarily related to our South Texas assets, and additions from extensions and discoveries of 39.7 MMBOE, primarily related to our Uinta Basin assets. Our proved reserve life index decreased to 8.9 years as of December 31, 2025, compared with 10.9 years as of December 31, 2024. Refer to Reserves in Part I, Items 1 and 2 of this report for additional discussion. The standardized measure of discounted future net cash flows was $6.0 billion as of December 31, 2025, compared with $7.3 billion as of December 31, 2024. The year-over-year decrease of 18 percent was primarily due to decreases in oil and NGL benchmark commodity prices during 2025. Refer to Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion.
Previous wording
Operational Activities. During 2024, successful operational execution drove strong well performance and capital efficiency across our asset portfolio. Our continued success in both our Midland Basin and South Texas programs is attributable to our top-tier assets and technical teams, and our commitment to geoscience, technology, and innovation. During the fourth quarter of 2024, we began integrating our Uinta Basin assets where we focused on delineation and development.
Current wording
Operational Activities. During 2025, successful operational execution drove strong well performance and capital efficiency across our asset portfolio. Our continued success in our Midland Basin, South Texas, and Uinta Basin programs is attributable to our top-tier assets and technical teams, and our commitment to geoscience, technology, and innovation.
Previous wording
In our Midland Basin program, we averaged four drilling rigs and one completion crew during 2024. Average net daily equivalent production volumes increased year-over-year by seven percent to 80.5 MBOE. Costs incurred during 2024 totaled
Current wording
In our Midland Basin program, we averaged three drilling rigs and one completion crew during 2025. Average net daily equivalent production volumes increased year-over-year by three percent to 82.8 MBOE. Costs incurred during 2025 totaled $548 million, or 38 percent, of our total 2025 costs incurred. Drilling and completion activities focused on developing formations within our RockStar and Sweetie Peck assets.
Previous wording
In our South Texas program, we averaged two drilling rigs and one completion crew during 2024. Average net daily equivalent production volumes increased year-over-year by six percent to 81.0 MBOE. Costs incurred during 2024 totaled $478.3 million, or 14 percent, of our total 2024 costs incurred. Drilling and completion activities were primarily focused on delineating and developing the Austin Chalk formation.
Current wording
In our South Texas program, we averaged one drilling rig and one completion crew during 2025. Average net daily equivalent production volumes decreased year-over-year by one percent to 80.3 MBOE. Costs incurred during 2025 totaled $361 million, or 25 percent, of our total 2025 costs incurred. Drilling and completion activities were primarily focused on delineating and developing the Austin Chalk formation.
Previous wording
In our Uinta Basin program, we averaged three drilling rigs and one completion crew during the fourth quarter of 2024. Average net daily equivalent production volumes totaled 36.1 MBOE for the fourth quarter of 2024, or 9.1 MBOE if calculated over the full year 2024. Costs incurred during 2024 totaled $2.3 billion, or 65 percent, of our total 2024 costs incurred, of which, over $2.1 billion related to acquisition costs. Drilling and completion activities primarily focused on delineating and developing the Lower Green River and Wasatch formations.
Current wording
In our Uinta Basin program, we averaged three drilling rigs and one completion crew during 2025. Average net daily equivalent production volumes increased to 43.7 MBOE for the full year 2025, compared to 36.1 MBOE for the fourth quarter of 2024. Costs incurred during 2025 totaled $481 million, or 33 percent, of our total 2025 costs incurred. Drilling and completion activities primarily focused on delineating and developing the Lower Green River and Wasatch formations.
Previous wording
(1) As of December 31, 2023, and 2024, the drilled but not completed well count included nine gross (nine net) wells that were not included in our five-year development plan, eight of which were in the Eagle Ford shale.
Current wording
(1) As of December 31, 2024, the drilled but not completed well count included nine gross (nine net) wells that were not included in our five-year development plan, eight of which were in the Eagle Ford shale. As of December 31, 2025, the drilled but not completed well count included two gross (two net) wells that were not included in our five year development plan, each of which are in the Eagle Ford shale.
Previous wording
Net equivalent production increased 12 percent for the year ended December 31, 2024, compared with 2023, comprised of increases of seven percent and six percent from our Midland Basin and South Texas assets, respectively, and 3.3 MMBOE of production during the fourth quarter of 2024 from our Uinta Basin assets. Refer to Overview of Selected Production and Financial Information, Including Trendsand Comparison of Financial Results and Trends Between 2024 and 2023 and Between 2023 and 2022 below for additional discussion of production.
Current wording
Net equivalent production increased 21 percent for the year ended December 31, 2025, compared with 2024. The increase was a result of a three percent increase from our Midland Basin assets, a full year of production from our Uinta Basin assets, and continued strong well performance. Refer to Overview of Selected Production and Financial Information, Including Trendsand Comparison of Financial Results and Trends Between 2025 and 2024 below for additional discussion of production.
Previous wording
As global commodities, the prices for oil, gas, and NGLs are affected by real or perceived geopolitical risks in various regions of the world, as well as the relative strength of the United States dollar compared to other currencies. Given the uncertainty surrounding global financial markets, production output from OPEC+, global shipping channel constraints and disruptions, fluctuations in oil and gas demand from China, War and Geopolitical Instability, changes in global oil inventory in storage, tariffs or trade restrictions, and the potential impacts of these issues on global commodity markets, we expect benchmark prices for oil, gas, and NGLs to remain volatile for the foreseeable future, and we cannot reasonably predict the timing or likelihood of any future impacts that may result, which could include inflation, supply chain disruptions, fluctuations in interest rates, and industry-specific impacts. Our realized prices at local sales points may also be affected by infrastructure capacity in the areas of our operations and beyond.
Current wording
(1)Our realized prices at local sales points may be affected by infrastructure capacity in the areas of our operations and beyond.
Previous wording
(1)Effective January 1, 2023, average OPIS price per barrel of NGL, historical or strip, assumes a composite barrel product mix of 42% Ethane, 28% Propane, 6% Isobutane, 11% Normal Butane, and 13% Natural Gasoline. For periods prior to 2023, average OPIS price per barrel of NGL, historical or strip, assumed a composite barrel product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline. These product mixes represent the industry standard composite barrel for the respective periods presented and do not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.
Current wording
(2)Average OPIS price per barrel of NGL, historical or strip, assumes a composite barrel product mix of 42% Ethane, 28% Propane, 6% Isobutane, 11% Normal Butane, and 13% Natural Gasoline. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.
Previous wording
(2)Net derivative settlements for the years ended December 31, 2024, 2023, and 2022, are included within the net derivative (gain) loss line item in the accompanying consolidated statements of operations (“accompanying statements of operations”).
Current wording
(2)Net derivative settlements for the years ended December 31, 2025, and 2024, are included within the net derivative gain line item in the accompanying consolidated statements of operations (“accompanying statements of operations”).
Previous wording
Average net daily equivalent production for the year ended December 31, 2024, increased 12 percent compared with 2023, as a result of an increased number of completions, strong well performance, and production from our Uinta Basin assets during the fourth quarter of 2024. Oil production as a percentage of total production increased to 47 percent in 2024 from 43 percent in 2023, as a result of increased oil production from both our Midland Basin and South Texas assets, in addition to oil production from our Uinta Basin assets. In 2025, we expect total production volumes and oil as a percentage of total production to each increase compared with 2024. Refer to Comparison of Financial Results and Trends Between 2024 and 2023 and Between 2023 and 2022 below for additional discussion.
Current wording
Average net daily equivalent production for the year ended December 31, 2025, increased 21 percent compared with 2024, resulting from a full year of production from our Uinta Basin assets, and continued strong well performance. Oil production as a percentage of total production increased to 53 percent in 2025 from 47 percent in 2024, resulting from a full year of oil production from our Uinta Basin assets, which averaged 87 percent oil production in 2025. In 2026, we expect an increase in total production volumes due to the integration of assets from the Civitas Merger. Refer to Comparison of Financial Results and Trends Between 2025 and 2024 below for additional discussion.
Previous wording
Our realized price on a per BOE basis remained flat for the year ended December 31, 2024, compared with 2023, primarily because a 24 percent increase in oil production was offset by decreases in oil and gas benchmark commodity prices. For the years ended December 31, 2024, and 2023, we recognized net gains on the settlement of our commodity derivative contracts of $1.10 per BOE and $0.49 per BOE, respectively.
Current wording
Our realized price on a per BOE basis decreased three percent for the year ended December 31, 2025, compared with 2024, primarily because of decreases in oil benchmark commodity prices partially offset by the increase in gas benchmark commodity prices. For the years ended December 31, 2025, and 2024, we recognized net gains on the settlement of our commodity derivative contracts of $1.75 per BOE and $1.10 per BOE, respectively.
Previous wording
LOE on a per BOE basis remained flat for the year ended December 31, 2024, compared with 2023, as increases in labor costs and certain other operating costs were offset by an increase in total net equivalent production and a decrease in workover expense due to the timing of activity. For 2025, we expect LOE on a per BOE basis to increase, compared with 2024, as our product mix continues to shift towards more oil production with our Uinta Basin assets, and as a result of expected increases in certain operating costs associated with our Midland Basin assets. We anticipate volatility in LOE on a per BOE basis as a result of changes in total production, timing of workover projects, changes in service provider costs, and industry activity, all of which affect total LOE.
Current wording
LOE on a per BOE basis increased 12 percent for the year ended December 31, 2025, compared with 2024, driven by the increased percentage of oil in our total production mix, which has higher lifting costs per BOE, and increases in certain operating costs. We anticipate volatility in LOE on a per BOE basis resulting from changes in production, timing of workover projects, changes in service provider costs, and industry activity, all of which affect total LOE.
Previous wording
Transportation costs on a per BOE basis increased nine percent for the year ended December 31, 2024, compared with 2023. This increase was due to a six percent increase in NGL production from our South Texas assets and 3.3 MMBOE of production from our Uinta Basin assets, both of which incur higher transportation costs than our Midland Basin assets. In general, we expect total transportation costs to fluctuate relative to changes in gas and NGL production from our South Texas assets and oil production from our Uinta Basin assets, where we incur a majority of our transportation costs. For 2025, we expect transportation costs on a per BOE basis to increase, compared with 2024, as a result of the addition of our Uinta Basin assets.
Current wording
Transportation costs on a per BOE basis increased 44 percent for the year ended December 31, 2025, compared with 2024. This increase was primarily due to 15.9 MMBOE of full year production from our Uinta Basin assets, which incur higher transportation costs on a per BOE basis compared to our Midland Basin and South Texas assets. In general, we expect total transportation costs to fluctuate relative to changes in oil production from our Uinta Basin assets and gas and NGL production from our South Texas assets, where we incur a majority of our transportation costs. For 2026, we expect transportation costs on a per BOE basis to remain relatively flat compared with 2025.
Previous wording
Production tax expense on a per BOE basis for the year ended December 31, 2024, decreased two percent compared with 2023, primarily as a result of a decrease in the realized price of gas. Our overall production tax rate was 4.3 percent and 4.4 percent for the years ended December 31, 2024, and 2023, respectively. We expect that our Uinta Basin assets will incur a lower production tax rate compared to our Midland Basin and South Texas assets. We generally expect production tax expense to correlate with oil, gas, and NGL production revenue on a per BOE and absolute basis. Product mix, the location of production, and incentives to encourage oil and gas development can also impact the amount of production tax expense that we recognize.
Current wording
Production tax expense on a per BOE basis for the year ended December 31, 2025, decreased nine percent compared with 2024, primarily resulting from a decrease in the realized price of oil, and full year operations for our Uinta Basin assets which incur a lower production tax rate compared to our Midland Basin and South Texas assets. Our overall production tax rate was 4.1 percent and 4.3 percent for the years ended December 31, 2025, and 2024, respectively. We generally expect production tax expense to correlate with oil, gas, and NGL production revenue on a per BOE and absolute basis. Product mix, the location of production, and incentives to encourage oil and gas development can also impact the amount of production tax expense that we recognize.
Previous wording
Ad valorem tax expense on a per BOE basis decreased 16 percent for the year ended December 31, 2024, compared with 2023, as a result of changes to the assessed values of our producing properties due to decreased commodity price assumptions used in the current year valuation, and increased net equivalent production. We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis as the valuation of our producing properties changes, which is generally driven by fluctuations in commodity prices, and can be impacted by changes in tax laws.
Current wording
Ad valorem tax expense on a per BOE basis decreased 18 percent for the year ended December 31, 2025, compared with 2024, primarily due to increased net equivalent production and changes to the assessed values of our producing properties. We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis as the valuation of our producing properties changes.
Previous wording
Depletion, depreciation, and amortization (“DD&A”) expense on a per BOE basis increased four percent for the year ended December 31, 2024, compared with 2023, due to a shift in production mix to our Uinta Basin assets. Our Midland Basin and Uinta Basin assets have higher DD&A rates than our South Texas assets. For 2025, we expect DD&A expense per BOE and on an absolute basis to increase, compared with 2024, primarily as a result of expected increased production resulting from the addition of our Uinta Basin assets, and a shift in our production mix. Our DD&A rate fluctuates as a result of changes in our production mix, changes in our total estimated proved reserve volumes, changes in capital allocation, impairments, acquisition and divestiture activity, and carrying cost funding and sharing arrangements with third parties.
Current wording
Depletion, depreciation, and amortization (“DD&A”) expense on a per BOE basis increased 23 percent for the year ended December 31, 2025, compared with 2024, due to increased production from our Uinta Basin assets, which caused a shift in the production mix towards our higher rate Midland Basin and Uinta Basin assets. For 2026, we expect DD&A expense on an absolute basis to increase compared with 2025, primarily reflecting anticipated higher production volumes and our expanded asset base. Our DD&A expense on a per BOE and absolute basis may fluctuate as a result of changes in our production mix, changes in our total estimated proved reserve volumes, changes in capital allocation, impairments, acquisition and divestiture activity, and carrying cost funding and sharing arrangements with third parties.
Previous wording
General and administrative (“G&A”) expense on a per BOE basis increased two percent for the year ended December 31, 2024, compared with 2023, primarily as a result of increases in certain G&A expenses resulting from the Uinta Basin Acquisition and increased compensation expense, partially offset by a 12 percent increase in average net equivalent production. For 2025, we expect G&A expense on an absolute basis to increase, compared with 2024, primarily as a result of an increase in employee headcount as a result of the Uinta Basin Acquisition and expected increases in compensation expense. We expect G&A expense on a per BOE basis to remain relatively flat, compared with 2024, as the expected increases in G&A expense on an absolute basis are expected to be mostly offset by increases in production. Certain components of G&A expense, and G&A expense on a per BOE basis, are impacted by the Company’s full year performance against performance targets established at the beginning of the year and, therefore, are subject to variability. Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for the definition of the Uinta Basin Acquisition.
Current wording
General and administrative (“G&A”) expense on a per BOE basis decreased four percent for the year ended December 31, 2025, compared with 2024, primarily driven by a higher rate of production growth relative to increases in G&A expense on an absolute basis. For 2026, we expect G&A expense on an absolute basis and on a per BOE basis to increase compared with 2025, primarily due to an increase in employee headcount as a result of the Civitas Merger, and expected increases in compensation expense and integration costs. Certain components of G&A expense, and G&A expense on a per BOE basis, are impacted by the Company’s full year performance against performance targets established at the beginning of the year and, therefore, are subject to variability.
Previous wording
Refer to Comparison of Financial Results and Trends Between 2024 and 2023 and Between 2023 and 2022 for additional discussion of operating expenses.
Current wording
Refer to Comparison of Financial Results and Trends Between 2025 and 2024 for additional discussion of operating expenses.
Previous wording
Average net daily equivalent production volumes for the year ended December 31, 2024, increased 12 percent compared with 2023, comprised of a seven percent increase from our Midland Basin assets, a six percent increase from our South Texas assets, and 9.1 MBOE of production from our Uinta Basin assets. As a result of decreases in benchmark oil and gas prices, realized prices for oil and gas decreased two percent and 27 percent, respectively, while the realized price for NGLs remained flat. The 13 percent increase in oil, gas, and NGL production revenue is primarily a result of the increase in average net daily equivalent production volumes. Oil, gas, and NGL production expense for the year ended December 31, 2024, increased 13 percent compared with 2023, as activity related to our Uinta Basin assets contributed to increases in transportation costs, LOE, and production tax expense.
Current wording
Average net daily equivalent production volumes for the year ended December 31, 2025, increased 21 percent compared with 2024, comprised of a three percent increase from our Midland Basin assets, and 43.7 MBOE of production from our Uinta Basin assets. As a result of decreases in benchmark oil and NGL prices, realized prices for oil and NGLs decreased 15 percent and three percent, respectively, while the realized price for gas increased 29 percent. Oil, gas, and NGL production revenue increased 17 percent, primarily resulting from a 21 percent increase in average net daily equivalent production volumes. Oil, gas, and NGL production expense for the year ended December 31, 2025, increased 39 percent compared with 2024, as activity related to our Uinta Basin assets contributed to increases in transportation costs, LOE, and production tax expense.
Previous wording
DD&A expense for the year ended December 31, 2024, increased 17 percent compared with 2023, primarily as a result of a combination of increased average net daily equivalent production, including the addition of production from our Uinta Basin assets during the fourth quarter of 2024, and a shift in production mix to our Uinta Basin assets. Our Midland Basin and Uinta Basin assets have higher DD&A rates than our South Texas assets. DD&A expense for the year ended December 31, 2023, increased 14 percent compared with 2022, primarily as a result of inflation and a five percent increase in average net daily equivalent production volumes, partially offset by a shift in production mix due to higher activity in our South Texas assets, which have a lower DD&A rate than our Midland Basin assets. Refer to Overview of Selected Production and Financial Information, Including Trends above for discussion of DD&A expense on a per BOE basis.
Current wording
DD&A expense for the year ended December 31, 2025, increased 49 percent compared with 2024, primarily resulting from increased production from our Uinta Basin assets during 2025. Our Midland Basin and Uinta Basin assets have higher DD&A rates than our South Texas assets. Refer to Overview of Selected Production and Financial Information, Including Trends above for discussion of DD&A expense on a per BOE basis.
Previous wording
Exploration expense increased eight percent for the year ended December 31, 2024, compared with 2023, primarily as a result of an increase in geological and geophysical expenses related to our Uinta Basin assets. Exploration expense fluctuates based on actual geological and geophysical studies we perform within an exploratory area, exploratory dry hole expense incurred, and changes in the amount of allocated overhead.
Current wording
Exploration expense decreased 11 percent for the year ended December 31, 2025, compared with 2024, primarily resulting from a decrease in geological and geophysical and other expenses. Exploration expense fluctuates based on actual geological and geophysical studies we perform within an exploratory area, exploratory dry hole expense incurred, and changes in the amount of allocated overhead.
Previous wording
G&A expense increased 14 percent for the year ended December 31, 2024, compared with 2023, primarily as a result of increases in certain G&A expenses resulting from the Uinta Basin Acquisition and increased compensation expense. Refer to Overview of Selected Production and Financial Information, Including Trends above for discussion of G&A expense, including G&A expense on a per BOE basis, and to Note 17 – Acquisitions in Part II, Item 8 of this report for the definition of the Uinta Basin Acquisition.
Current wording
G&A expense increased 17 percent for the year ended December 31, 2025, compared with 2024, primarily due to increased compensation costs associated with additional headcount from the Uinta Basin Acquisition. Refer to Overview of Selected Production and Financial Information, Including Trends above for discussion of G&A expense, including G&A expense on a per BOE basis.
Previous wording
Net derivative (gain) loss is a result of changes in fair values associated with fluctuations in the forward price curves for the commodities underlying our outstanding derivative contracts and the monthly cash settlements of our derivative positions during the period. We expect increases in benchmark commodity prices to result in net derivative losses, and decreases in benchmark commodity prices to result in net derivative gains, as measured against our derivative contract prices. Refer to Note 7 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.
Current wording
Net derivative gain is a result of changes in fair values associated with fluctuations in the forward price curves for the commodities underlying our outstanding derivative contracts and the monthly cash settlements of our derivative positions during the period. We expect increases in benchmark commodity prices to result in net derivative losses, and decreases in benchmark commodity prices to result in net derivative gains, as measured against our derivative contract prices. Refer to Note 7 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.
Previous wording
Interest expense increased 54 percent for the year ended December 31, 2024, compared with 2023, as a result of the issuance of our 2029 Senior Notes and 2032 Senior Notes during 2024, an increase in interest expense associated with borrowings under our revolving credit facility, and a $9.0 million fee that was paid to secure firm commitments for up to $1.2 billion of senior unsecured 364-day bridge term loans (“Bridge Facility”) in connection with the Uinta Basin Acquisition. We did not draw on the Bridge Facility, and after issuance of the 2029 Senior Notes and 2032 Senior Notes on July 25, 2024, we terminated the Bridge Facility, and the associated fees were recognized as interest expense. Total interest expense can vary based on the amount of our outstanding fixed-rate debt securities, fluctuations in the amount of capitalized interest as a result of the timing of the development of our wells in progress, and due to the timing and amount of borrowings under our revolving credit facility. Refer to Overview of Liquidity and Capital Resources below, Significant Developments in 2024 in Part I, Items 1 and 2 for the definitions of 2029 Senior Notes and 2032 Senior Notes, and to Note 5 – Long-Term Debt and Note 17 – Acquisitionsin Part II, Item 8 of this report for additional discussion and definitions.
Current wording
Interest expense increased 23 percent for the year ended December 31, 2025, compared with 2024, as a result of the issuance of our 2029 Senior Notes and 2032 Senior Notes during the third quarter of 2024 and an increase in interest expense associated with borrowings under our revolving credit facility. Total interest expense can vary based on the amount of our outstanding fixed-rate debt securities, fluctuations in the amount of capitalized interest resulting from the timing of the development of our wells in progress, and due to the timing and amount of borrowings under our revolving credit facility. Refer to Overview of Liquidity and Capital Resources below and to Note 5 – Long-Term Debtin Part II, Item 8 of this report for additional discussion and definitions.
Previous wording
During 2024, we made federal estimated tax payments of $25.5 million and state tax payments, net of refunds, of $1.4 million.
Current wording
During 2025, we made estimated tax payments of $8 million and received a federal refund of $4 million during the fourth quarter of 2025.
Previous wording
Refer to Critical Accounting Estimates below and Note 4 – Income Taxes in Part II, Item 8 of this report for further discussion.
Current wording
Refer to Note 4 – Income Taxesin Part II, Item 8 of this report for further discussion.
Previous wording
Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan while continuing to meet our current financial obligations. We continue to manage the duration and level of our drilling and completion service commitments in order to maintain flexibility with regard to our activity level and capital expenditures.
Current wording
Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan while continuing to meet our financial obligations, including near-term maturities of our outstanding Senior Notes. We continue to manage the duration and level of our drilling and completion service commitments in order to maintain flexibility with regard to our activity level and capital expenditures.
Previous wording
During 2024, we issued our 2029 Senior Notes and 2032 Senior Notes. See below for discussion on how the net proceeds received were used, and to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion.
Current wording
During 2024, we issued our 2029 Senior Notes and 2032 Senior Notes. See below for discussion on how the net proceeds received were used, and refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion.
Previous wording
Our credit ratings affect the availability of, and cost for us to borrow, additional funds. One major credit rating agency upgraded our credit ratings following the close of the Uinta Basin Acquisition on October 1, 2024, citing our increased size and scale, increased inventory, increased oil percentage of expected production, strong operational performance, our priority of improving our leverage metrics, our ability to consistently generate cash flows, and our use of financial derivative instruments as part of our financial risk management program. Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for the definition of the Uinta Basin Acquisition.
Current wording
Our credit ratings affect the availability of, and cost for us to borrow, additional funds. Two major credit rating agencies upgraded our credit ratings following the close of the Civitas Merger on January 30, 2026, citing our increased size, scale and diversification, and enhanced and consistently positive free cash flow generation.
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Rearranged current paragraphs (5)
Current report — wording carried from elsewhere
•Net equivalent production of 75.5 MMBOE drove net income of $648 million, net cash provided by operating activities of $2.0 billion, and Adjusted EBITDAX, a non-GAAP financial measure, of $2.3 billion. Refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to net income and net cash provided by operating activities.
Current report — wording carried from elsewhere
Comparison of Financial Results and Trends Between 2025 and 2024
Current report — wording carried from elsewhere
Amendment and Fourth Amendment and additional discussion, as well as the presentation of the outstanding balance, total amount of letters of credit, and available borrowing capacity under the Credit Agreement as of February 2, 2026, December 31, 2025, and December 31, 2024.
Current report — wording carried from elsewhere
The following table summarizes our daily weighted-average revolving credit facility balance during the periods presented:
Current report — wording carried from elsewhere
February 2, 2026, we do not expect any material proved oil and gas property impairments in the first quarter of 2026 resulting from commodity price impacts.
Rearranged previous paragraphs (3)
Previous report — wording carried elsewhere
$720.9 million, or 21 percent, of our total 2024 costs incurred. Drilling and completion activities focused on developing formations within our RockStar, Sweetie Peck, and Klondike assets.
Previous report — wording carried elsewhere
The following table presents the changes in our average net daily equivalent production, oil, gas, and NGL production revenue, and oil, gas, and NGL production expense, by area, between the years ended December 31, 2023, and 2022:
Previous report — wording carried elsewhere
Net cash provided by operating activities decreased for the year ended December 31, 2023, compared with 2022, primarily as a result of a $937.3 million decrease in cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, and an increase of $44.5 million in cash paid for LOE and ad valorem taxes, partially offset by a decrease of $749.3 million in cash paid on settled derivative trades and a $45.5 million decrease in cash paid for interest.