SM Energy Company

02/26/2026 | Press release | Distributed by Public on 02/26/2026 07:57

Annual Report for Fiscal Year Ending 12-31, 2025 (Form 10-K)

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion includes forward-looking statements. Refer to the Cautionary Information about Forward-Looking Statementssection 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.
Overview of the Company
Merger with Civitas
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.
On January 30, 2026, we completed the Civitas Mergerin accordance with the terms of the Merger Agreement. Civitaswas 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 willcreate 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.
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 millionshares to holders of Civitas common stock, representing 52 percentof 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.
Refer to Note 17 - Mergers, Acquisitions, and Divestituresin Part II, Item 8 of this report for additional discussion.
South Texas Asset Divestiture
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 Divestituresin Part II, Item 8 for additional discussion and the definitions of Purchase Price and Transaction.
General Overview
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.
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.
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 Outlook for discussion of our 2026 capital program.
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.
Market Trends and Uncertainties
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.
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.
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.
Outlook
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 Outlook in Part I, Items 1 and 2 of this report for additional discussion.
2025 Financial and Operational Highlights
During 2025:
•We completed the integration of the Uinta Basin assets into our portfolio. Refer to Note 17 - Mergers, Acquisitions, and Divestituresin Part II, Item 8 of this report for additional discussion of the Uinta Basin Acquisition.
•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.
•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.
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.
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.
Operational activities during the year ended December 31, 2025, resulted in the following:
•Net cash provided by operating activities of $2.0 billion, compared with $1.8 billion for 2024.
•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.
•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.
•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.
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.
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.
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.
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.
The table below provides a summary of changes in our drilled but not completed well count and current year drilling, completion, and acquisition activity in our operated programs for the year ended December 31, 2025:
Midland Basin
South Texas (1)
Uinta Basin Total
Gross Net Gross Net Gross Net Gross Net
Wells drilled but not completed at December 31, 2024
40 29 35 35 48 38 123 102
Wells drilled 47 37 30 29 52 38 129 104
Wells completed (72) (53) (33) (33) (62) (49) (167) (135)
Other (2) (3)
- - (7) (7) - 1 (7) (6)
Wells drilled but not completed at December 31, 2025
15 12 25 24 38 28 78 64
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Note: Amounts may not calculate due to rounding.
(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.
(2)The South Texas adjustments relate to previously drilled wells that we no longer intend to complete.
(3)The Uinta Basin adjustment relates to the acquisition of additional working interest in existing drilled but not completed wells.
Costs Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, are summarized as follows:
For the Year Ended
December 31, 2025
(in millions)
Development costs $ 1,333
Exploration costs 94
Acquisitions
Proved properties (5)
Unproved properties 26
Total, including asset retirement obligations (1)
$ 1,448
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(1)Refer to the caption Costs Incurred in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.
Production Results. The table below presents the disaggregation of our net production volumes by product type for each of our assets for the year ended December 31, 2025:
Midland Basin South Texas
Uinta Basin
Total
Net production volumes:
Oil (MMBbl) 19.2 7.3 13.9 40.3
Gas (Bcf) 66.3 71.7 12.5 150.5
NGLs (MMBbl) - 10.1 - 10.1
Equivalent (MMBOE) 30.2 29.3 15.9 75.5
Average net daily equivalent (MBOE per day) 82.8 80.3 43.7 206.8
Relative percentage 40 % 39 % 21 % 100 %
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Note: Amounts may not calculate due to rounding.
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 Trends and Comparison of Financial Results and Trends Between 2025 and 2024below for additional discussion of production.
Oil, Gas, and NGL Prices
Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period, before the effect of net derivative settlements. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials, and contracted pricing benchmarks for these products.
The following table summarizes commodity price data, as well as the effect of net derivative settlements, for the years ended December 31, 2025, and 2024:
For the Years Ended December 31,
2025 2024
Oil (per Bbl):
Average NYMEX contract monthly price $ 64.81 $ 75.72
Realized price (1)
$ 63.52 $ 74.49
Effect of oil net derivative settlements $ 1.66 $ 0.43
Gas:
Average NYMEX monthly settle price (per MMBtu) $ 3.43 $ 2.27
Realized price (per Mcf) (1)
$ 2.35 $ 1.82
Effect of gas net derivative settlements (per Mcf) $ 0.44 $ 0.43
NGLs (per Bbl):
Average OPIS price (2)
$ 27.19 $ 28.30
Realized price (1)
$ 22.22 $ 23.01
Effect of NGL net derivative settlements $ (0.21) $ (0.25)
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(1) Our realized prices at local sales points may be affected by infrastructure capacity in the areas of our operations and beyond.
(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.
The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of February 2, 2026, and December 31, 2025:
As of February 2, 2026 As of December 31, 2025
NYMEX WTI oil (per Bbl) $ 60.38 $ 57.08
NYMEX Henry Hub gas (per MMBtu) $ 3.76 $ 3.72
OPIS NGLs (per Bbl) $ 24.77 $ 23.46
We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives, and decisions regarding entering into commodity derivative contracts are overseen by a financial risk management committee consisting of certain senior executive officers and finance personnel. We make decisions about the amount of our expected production that we cover by derivatives based on the amount of debt on our balance sheet, the level of capital commitments and long-term obligations we have in place, and the terms and futures prices that are made available by our approved counterparties. With our current commodity derivative contracts, we believe we have partially reduced our exposure to volatility in commodity prices and basis differentials in the near term. Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil and gas prices while also setting a price floor below which we are insulated from further price decreases. Refer to Note 7 - Derivative Financial Instruments in Part II, Item 8 of this report and to Commodity Price Risk in Overview of Liquidity and Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.
Financial Results of Operations and Additional Comparative Data
The tables below provide information regarding selected production and financial information for the three months ended December 31, 2025, and the preceding three quarters:
For the Three Months Ended
December 31, September 30, June 30, March 31,
2025 2025 2025 2025
(in millions)
Production (MMBOE) 19.0 19.7 19.0 17.8
Oil, gas, and NGL production revenue $ 703 $ 811 $ 785 $ 840
Oil, gas, and NGL production expense $ 207 $ 229 $ 224 $ 225
Depletion, depreciation, and amortization
$ 319 $ 325 $ 293 $ 270
Exploration $ 18 $ 12 $ 15 $ 12
General and administrative $ 40 $ 39 $ 42 $ 39
Net income $ 109 $ 155 $ 202 $ 182
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Note: Amounts may not calculate due to rounding.
Selected Performance Metrics
For the Three Months Ended
December 31, September 30, June 30, March 31,
2025 2025 2025 2025
Average net daily equivalent production (MBOE per day) 206.9 213.8 209.1 197.3
Lease operating expense (per BOE) $ 5.55 $ 5.67 $ 5.52 $ 6.13
Transportation costs (per BOE) $ 3.67 $ 3.77 $ 4.13 $ 3.92
Production taxes as a percent of oil, gas, and NGL production revenue 3.8 % 4.1 % 3.9 % 4.4 %
Ad valorem tax expense (per BOE) $ 0.23 $ 0.51 $ 0.54 $ 0.55
Depletion, depreciation, and amortization (per BOE)
$ 16.73 $ 16.54 $ 15.40 $ 15.20
General and administrative (per BOE) $ 2.10 $ 2.00 $ 2.21 $ 2.22
____________________________________________
Note: Amounts may not calculate due to rounding.
Overview of Selected Production and Financial Information, Including Trends
For the Years Ended
December 31,
Amount Change Between Periods
Percent Change Between Periods
2025 2024
Net production volumes:(1)
Oil (MMBbl) 40.3 29.4 11.0 37 %
Gas (Bcf) 150.5 137.0 13.5 10 %
NGLs (MMBbl) 10.1 10.2 (0.1) (1) %
Equivalent (MMBOE) 75.5 62.4 13.1 21 %
Average net daily production: (1)
Oil (MBbl per day) 110.5 80.2 30.2 38 %
Gas (MMcf per day) 412.3 374.3 38.1 10 %
NGLs (MBbl per day) 27.6 27.9 (0.3) (1) %
Equivalent (MBOE per day) 206.8 170.5 36.3 21 %
Oil, gas, and NGL production revenue (in millions): (1)
Oil production revenue $ 2,561 $ 2,187 $ 374 17 %
Gas production revenue 353 249 104 42 %
NGL production revenue 224 235 (11) (5) %
Total oil, gas, and NGL production revenue $ 3,138 $ 2,671 $ 467 17 %
Oil, gas, and NGL production expense (in millions): (1)
Lease operating expense $ 431 $ 319 $ 112 35 %
Transportation costs 292 167 125 75 %
Production taxes 127 116 11 10 %
Ad valorem tax expense 35 35 - (1) %
Total oil, gas, and NGL production expense $ 885 $ 637 $ 248 39 %
Realized price:
Oil (per Bbl) $ 63.52 $ 74.49 $ (10.97) (15) %
Gas (per Mcf) $ 2.35 $ 1.82 $ 0.53 29 %
NGLs (per Bbl) $ 22.22 $ 23.01 $ (0.79) (3) %
Per BOE $ 41.58 $ 42.81 $ (1.23) (3) %
Per BOE data: (1)
Oil, gas, and NGL production expense:
Lease operating expense $ 5.71 $ 5.11 $ 0.60 12 %
Transportation costs 3.87 2.68 1.19 44 %
Production taxes 1.69 1.86 (0.17) (9) %
Ad valorem tax expense 0.46 0.56 (0.10) (18) %
Total oil, gas, and NGL production expense (1)
$ 11.72 $ 10.21 $ 1.51 15 %
Depletion, depreciation, and amortization
$ 15.99 $ 12.97 $ 3.02 23 %
General and administrative $ 2.13 $ 2.22 $ (0.09) (4) %
Net derivative settlement gain (2)
$ 1.75 $ 1.10 $ 0.65 59 %
Earnings per share information (in millions, except per share data): (3)
Basic weighted-average common shares outstanding 115 115 - - %
Diluted weighted-average common shares outstanding 115 116 (1) (1) %
Basic net income per common share $ 5.65 $ 6.71 $ (1.06) (16) %
Diluted net income per common share $ 5.64 $ 6.67 $ (1.03) (15) %
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(1)Amounts and percentage changes may not calculate due to rounding.
(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").
(3)Refer to Note 9 - Earnings Per Share in Part II, Item 8 of this report for additional discussion.
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.
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.
We present certain information on a per BOE basis in order to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis and discussion.
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.
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.
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.
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.
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.
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.
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.
Refer to Comparison of Financial Results and Trends Between 2025 and 2024 for additional discussion of operating expenses.
Comparison of Financial Results and Trends Between 2025 and 2024
Average net daily equivalent production, production revenue, and production expense
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, 2025, and 2024:
Average Net Equivalent Production Increase (Decrease) Oil, Gas, and NGL Production Revenue Increase (Decrease) Oil, Gas, and NGL Production Expense Increase
(MBOE per day) (in millions) (in millions)
Midland Basin 2.4 $ (194.8) $ 9.2
South Texas (0.7) (9.4) 28.2
Uinta Basin
34.6 671.3 210.6
Total 36.3 $ 467.1 $ 247.9
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Note: Amounts may not calculate due to rounding.
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.
Refer to Overview of Selected Production and Financial Information, Including Trends above for additional discussion, including discussion of trends on a per BOE basis.
Depletion, depreciation, and amortization
For the Years Ended December 31,
2025 2024
(in millions)
Depletion, depreciation, and amortization $ 1,207 $ 809
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.
Exploration
For the Years Ended December 31,
2025 2024
(in millions)
Geological, geophysical, and other expenses $ 17 $ 28
Overhead 40 36
Total exploration $ 57 $ 64
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.
General and administrative
For the Years Ended December 31,
2025 2024
(in millions)
General and administrative $ 161 $ 138
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.
Net derivative gain
For the Years Ended December 31,
2025 2024
(in millions)
Net derivative gain $ (178) $ (50)
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 Instrumentsin Part II, Item 8 of this report for additional discussion.
Interest expense
For the Years Ended December 31,
2025 2024
(in millions)
Interest expense $ (173) $ (141)
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 Debt in Part II, Item 8 of this report for additional discussion and definitions.
Income tax expense
For the Years Ended December 31,
2025 2024
(in millions, except tax rate)
Income tax expense $ (182) $ (196)
Effective tax rate 22.0 % 20.3 %
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.
During 2025, we made estimated tax payments of $8 million and received a federal refund of $4 million during the fourth quarter of 2025.
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.
Refer to Note 4 - Income Taxes in Part II, Item 8 of this report for further discussion.
Overview of Liquidity and Capital Resources
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.
Sources of Cash
We expect to fund our 2026 capital expenditures and return of capital program with cash flows from operations, with any remaining cash needs being funded by borrowings under our revolving credit facility. Although we expect cash flows from these sources to be sufficient for 2026, we may also elect to raise funds through new debt or equity offerings or from other sources of financing. If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our current stockholders could be diluted, and these newly issued securities may have rights, preferences, or privileges senior to those of existing stockholders and bondholders. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs.
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 Debtin Part II, Item 8 of this report for additional discussion.
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.
All of our sources of liquidity can be affected by the general conditions of the broader economy, force majeure events, fluctuations in commodity prices, operating costs, interest rate changes, tax law changes, and volumes produced, all of which affect us and our industry.
We have no control over the market prices for oil, gas, and NGLs, although we may be able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of commodity derivative contracts as part of our financial risk management program. Commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise over the price established by the commodity derivative contract. Refer to Note 7 - Derivative Financial Instrumentsin Part II, Item 8 of this report for additional information about our commodity derivative contracts currently in place and the timing of settlement of those contracts.
Credit Agreement
Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $3.0 billion. As of December 31, 2025, the borrowing base and aggregate revolving lender commitments under our Credit Agreement were $3.0 billion and $2.0 billion, respectively. The borrowing base is subject to regular, semi-annual redetermination, and considers the value of both our proved oil and gas properties reflected in our most recent reserve report and commodity derivative contracts, each as determined by our lender group. The next borrowing base redetermination date is scheduled to occur on April 1, 2026. During, 2025 we entered into the Third Amendment with our lenders to amend the springing maturity provision of the Credit Agreement to provide a more flexible structure based on the amount of our short-term debt outstanding and our borrowing availability. No individual bank participating in our Credit Agreement represents more than 10 percent of the lender commitments under the Credit Agreement. We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring that we maintain certain financial ratios, as set forth in the Credit Agreement. We were in compliance with all financial and non-financial covenants as of December 31, 2025, and through the filing of this report. In connection with the closing of the Civitas Merger on January 30, 2026, the Company and its lenders entered into the Fourth Amendment to the Credit Agreement, which, among other things, increased the aggregate revolving lender commitments available under our Credit Agreement to $2.5 billion and increased the borrowing base to $5.0 billion. Refer to Note 5 - Long-Term Debtin Part II, Item 8 of this report for definitions of the Third
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.
The following table summarizes our daily weighted-average revolving credit facility balance during the periods presented:
For the Years Ended December 31,
2025 2024
(in millions)
Daily weighted-average revolving credit facility balance
$ 50 $ 57
The amount we borrow under our revolving credit facility is impacted by cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities including open market debt repurchases, debt redemptions, and repayment of scheduled debt maturities, other financing activities, and our capital expenditures, including acquisitions.
Weighted-Average Interest and Weighted-Average Borrowing Rates
Our weighted-average interest rate includes paid and accrued interest, fees on the unused portion of the aggregate revolving lender commitment amount under the Credit Agreement, letter of credit fees, and the non-cash amortization of deferred financing costs. Our weighted-average borrowing rate includes paid and accrued interest only.
The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the years ended December 31, 2025 and 2024:
For the Years Ended December 31,
2025 2024
Weighted-average interest rate 7.4 % 7.6 %
Weighted-average borrowing rate 6.8 % 6.6 %
Our weighted-average interest rate decreased for the year ended December 31, 2025, compared with 2024, primarily due to decreased borrowings under our revolving credit facility. Our weighted-average borrowing rate increased for the year ended December 31, 2025, compared with 2024, primarily as a result of the issuance of our 2029 Senior Notes and 2032 Senior Notes during 2024, which have greater outstanding aggregate principal balances and higher interest rates compared with our other outstanding Senior Notes and our 5.625% Senior Notes due June 1, 2025 ("2025 Senior Notes") that we redeemed during the third quarter of 2024. The rates disclosed in the table above for the year ended December 31, 2024, do not reflect the $9 million fee paid to secure firm commitments for senior unsecured bridge term loans in connection with the Uinta Basin Acquisition.
Our weighted-average interest rate and weighted-average borrowing rate are affected by the occurrence and timing of long-term debt issuances and redemptions and the average outstanding balance on our revolving credit facility. Additionally, our weighted-average interest rate is affected by the fees paid on the unused portion of our aggregate revolving lender commitments. The rates disclosed in the above table do not reflect certain amounts associated with the repurchase or redemption of Senior Notes, such as the accelerated expense recognition of the unamortized deferred financing costs and unamortized discounts, as these amounts are netted against the associated gain or loss on extinguishment of debt. The 2025 Senior Notes were redeemed at their par value on August 26, 2024 and after this date, the weighted-average interest rate was no longer affected by the non-cash amortization of deferred financing costs of the 2025 Senior Notes.
Refer to Significant Developments in 2025 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 in Part II, Item 8 of this report for additional discussion and definitions.
Uses of Cash
We use cash for the development, exploration, and acquisition of oil and gas properties; for the payment of operating and general and administrative costs, income taxes, debt obligations, including interest and early repayments or redemptions, and dividends; and for repurchases of shares of our outstanding common stock under the Stock Repurchase Program. Expenditures for the development, exploration, and acquisition of oil and gas properties are the primary use of our capital resources. During 2025, we spent $1.5 billion on capital expenditures and on acquisitions of proved and unproved oil and gas properties. This amount differs from the costs incurred amount of $1.4 billion for the year ended December 31, 2025, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, and exploration overhead amounts. Refer to Costs Incurred in Supplemental Oil and Gas Information (unaudited)in Part II, Item 8 of this report for additional discussion.
The amount and allocation of our future capital expenditures will depend upon a number of factors, including our cash flows from operating, investing, and financing activities, our ability to execute our development program, inflation, and the number and size of acquisitions that we complete. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, tax law and other regulatory changes, and the timing and results of our exploration and development activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget and guidance to assess if changes are necessary based on current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors.
Changes to the Internal Revenue Code ("IRC") and federal income tax laws could increase our corporate income tax rate and eliminate or reduce current tax deductions, such as those for intangible drilling costs, depreciation of equipment costs, and other deductions which currently reduce our taxable income. The CAMT and other possible future legislation could reduce our net cash provided by operating activities resulting in a reduction of available funding. Refer to Comparison of Financial Results and Trends Between 2025 and 2024 above for additional discussion.
We may from time to time repurchase shares of our common stock, or repurchase or redeem all or portions of our outstanding debt securities, for cash, through exchanges for other securities, or a combination of both. Such repurchases or redemptions may be made in open market transactions, privately negotiated transactions, tender offers, pursuant to contractual provisions, or otherwise. Any such repurchases or redemptions will depend on our business strategy, prevailing market conditions, our liquidity requirements, contractual restrictions or covenants, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material.
During the years ended December 31, 2025, and 2024, we repurchased and subsequently retired 444,705 shares and 1,771,191 shares, respectively, of our common stock at a cost, excluding excise taxes, commissions, and fees, of $12 million and $84 million, respectively. As of December 31, 2025, $488 million remained available under the Stock Repurchase Program for repurchases of our common stock through December 31, 2027. Effective January 1, 2023, shares of common stock repurchased, net of shares of common stock issued, are subject to a one percent excise tax imposed by the IRA. We paid a minimal amount of excise tax related to common stock repurchases during 2025. Refer to Note 3 - Equity in Part II, Item 8 of this report for discussion of the Stock Repurchase Program.
During the years ended December 31, 2025, and 2024, we paid $92 million and $85 million, respectively, in dividends to our stockholders. Dividends paid were $0.80 and $0.74, per share during the years ended December 31, 2025, and 2024, respectively. Beginning in the first quarter of 2026, dividends are expected to be declared and paid within the same quarter, rather than being paid in the quarter subsequent to declaration. As a result of this timing change, cash dividend payments during 2026 are expected to include five payments, consisting of the fourth quarter 2025 dividend paid in the first quarter of 2026, plus the four quarterly dividends declared and paid during 2026. In February of 2026, our Board of Directors approved a 10 percent increase to our annual base dividend to $0.88 per share, payable quarterly, effective beginning with the March 2026 dividend. We currently intend to continue paying dividends to our stockholders for the foreseeable future, subject to our future earnings, our financial condition, covenants under our Credit Agreement and indentures governing each series of our outstanding Senior Notes, and other factors that could arise. The payment and amount of future dividends remain at the discretion of our Board of Directors.
During 2024, we redeemed all of the $349 million of aggregate principal amount outstanding of our 2025 Senior Notes. Additionally, we used a portion of the net proceeds from the 2029 Senior Notes and 2032 Senior Notes, cash on hand, and borrowings under our revolving credit facility to fund our proportionate share of the Uinta Basin Acquisition. Refer to Significant Developments in 2025 in Part I, Items 1 and 2 for the definitions of 2029 Senior Notes and 2032 Senior Notes, and to Note 5 - Long-Term Debtand Note 17 - Mergers, Acquisitions, and Divestitures in Part II, Item 8 of this report for additional discussion and definitions.
Analysis of Cash Flow Changes Between 2025 and 2024
The following tables present changes in cash flows between the years ended December 31, 2025 and 2024, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying consolidated statements of cash flows ("accompanying statements of cash flows") in Part II, Item 8 of this report.
Operating Activities
For the Years Ended December 31,
Amount Change Between Periods
2025 2024
(in millions)
Net cash provided by operating activities $ 2,011 $ 1,783 $ 228
Net cash provided by operating activities increased for the year ended December 31, 2025, compared with 2024, primarily resulting from a $474 million increase in cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, and an increase of $60 million in cash received on settled derivative trades. These amounts were partially offset by an increase of $169 million in cash paid for LOE, ad valorem taxes, and certain G&A expenses, and an increase of $78 million in cash
paid for interest. Net cash provided by operating activities was also affected by the timing of payments made between us and XCL Resources related to activity occurring after the closing date of the Uinta Basin Acquisition. Refer to Note 17 - Mergers, Acquisitions, and Divestituresin Part II, Item 8 of this report for additional discussion and definitions.
Net cash provided by operating activities is affected by working capital changes and the timing of cash receipts and disbursements.
Investing Activities
For the Years Ended December 31,
Amount Change Between Periods
2025 2024
(in millions)
Net cash used in investing activities $ (1,468) $ (3,407) $ 1,939
Net cash used in investing activities decreased for the year ended December 31, 2025, compared with 2024, resulting from $2.1 billion of cash paid for the Uinta Basin Acquisition in 2024, partially offset by a $127 million increase in capital expenditures. Refer to Note 17 - Mergers, Acquisitions, and Divestituresin Part II, Item 8 of this report for additional discussion of the Uinta Basin Acquisition.
Financing Activities
For the Years Ended December 31,
Amount Change Between Periods
2025 2024
(in millions)
Net cash provided by (used in) financing activities $ (175) $ 1,008 $ (1,183)
Net cash used in financing activities during the year ended December 31, 2025, primarily related to $92 million of dividends paid to our stockholders, net repayments under our revolving credit facility of $69 million, and $13 million, including commission and fees, paid to repurchase and subsequently retire 444,705 shares of our common stock under the Stock Repurchase Program.
Net cash provided by financing activities during the year ended December 31, 2024, primarily related to net cash proceeds of $1.5 billion from the issuance of our 2029 Senior Notes and 2032 Senior Notes, and net borrowings under our revolving credit facility of $69 million, partially offset by $349 million of cash paid to redeem our 2025 Senior Notes. Additionally, we paid $86 million, including commission and fees, to repurchase and subsequently retire 1,771,191 shares of our common stock under the Stock Repurchase Program, and paid $85 million of dividends to our stockholders.
Refer to Note 3 - Equity in Part II, Item 8 of this report for additional discussion of our Stock Repurchase Program and Note 5 - Long-Term Debtin Part II, Item 8 of this report for additional discussion and definitions related to our debt transactions.
Interest Rate Risk
We are exposed to market and credit risk due to the floating interest rate associated with any outstanding balance on our revolving credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the revolving credit facility's fair value but will not affect results of operations or cash flows. Conversely, for the portion of the revolving credit facility that has a floating interest rate, interest rate changes will not affect the fair value but will affect future results of operations and cash flows. Changes in interest rates do not affect the amount of interest we pay on our fixed-rate Senior Notes, but can affect their fair values. As of December 31, 2025, our outstanding principal amount of fixed-rate debt totaled $2.7 billion and we had no floating-rate debt outstanding. As of December 31, 2024, our outstanding principal amount of fixed-rate debt totaled $2.7 billion and our floating-rate debt outstanding totaled $69 million. Refer to Note 8 - Fair Value Measurementsin Part II, Item 8 of this report for additional discussion on the fair values of our Senior Notes.
Commodity Price Risk
The prices we receive for our oil, gas, and NGL production directly affect our revenue, profitability, access to capital, ability to return capital to our stockholders, and future rate of growth. Oil, gas, and NGL prices are subject to unpredictable fluctuations resulting from a variety of factors that are typically beyond our control, including changes in supply and demand associated with the broader macroeconomic environment, constraints on gathering systems, processing facilities, pipelines, rail systems, and other transportation systems, and weather-related events. The markets for oil, gas, and NGLs have been volatile, especially over the last decade, and
remain subject to high levels of uncertainty and volatility related to production output from OPEC+, fluctuations in oil and gas demand from China, global shipping channel constraints and disruptions, War and Geopolitical Instability, tariffs or trade restrictions, and the potential impacts of these issues on global commodity and financial markets. These circumstances have contributed to inflation, 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. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Refer to Risk Factors - Risks Related to Commodity Prices and Global Macroeconomics in Part I, Item 1A of this report. Based on our production for 2025, and 2024, a 10 percent decrease in our average realized prices for oil, gas, and NGLs would have reduced our oil, gas, and NGL production revenues by approximately $256 million, $35 million, and $22 million, respectively, for 2025, and $219 million, $25 million and $24 million, respectively, for 2024. If commodity prices had been 10 percent lower, our net derivative settlements for the year ended December 31, 2025, would have offset the declines in oil, gas, and NGL production revenue by approximately $106 million.
We enter into commodity derivative contracts in order to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of December 31, 2025, and 2024, a 10 percent increase or decrease in the forward curves associated with our oil, gas, and NGL commodity derivative instruments would have changed our net derivative positions for these products by approximately $57 million, $36 million, and $1 million, respectively, for 2025, and $52 million, $23 million, and $2 million, respectively, for 2024.
Off-Balance Sheet Arrangements
We have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities ("SPE" or "SPEs"). Refer to Off-Balance Sheet Arrangements within Note 1 - Summary of Significant Accounting Policiesin Part II, Item 8 of this report for additional discussion.
Critical Accounting Estimates
Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The preparation of these consolidated financial statements in conformity with GAAP requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses, as well as the disclosure of contingent assets and liabilities as of the date of our consolidated financial statements. We base our assumptions and estimates on historical experience and various other sources that we believe to be reasonable under the circumstances. Actual results may differ from the estimates we calculate as a result of changes in circumstances, global economics and politics, and general business conditions. A summary of our significant accounting policies is detailed in Note 1 - Summary of Significant Accounting Policies in Part II, Item 8 of this report. We have outlined below, those policies identified as being critical to the understanding of our business and results of operations and that require the application of significant management judgment.
Successful Efforts Method of Accounting. GAAP provides two alternative methods for the oil and gas industry to use in accounting for oil and gas producing activities. These two methods are generally known in our industry as the full cost method and the successful efforts method, and both methods are widely used. The methods are different enough that in many circumstances the same set of facts will provide materially different financial statement results within a given year. We have chosen the successful efforts method of accounting for our oil and gas producing activities. A more detailed description is included inNote 1 - Summary of Significant Accounting Policies of Part II, Item 8 of this report.
Oil and Gas Reserve Quantities. Our estimated proved reserve quantities and future net cash flows are critical to understanding the value of our business. They are used in comparative financial ratios and are the basis for significant accounting estimates in our consolidated financial statements, including the calculations of DD&A expense, impairment of proved and unproved oil and gas properties, asset retirement obligations, and purchase price allocations. Refer to Oil and Gas Producing Activities inNote 1 - Summary of Significant Accounting Policies of Part II, Item 8 of this report for additional discussion on our accounting policies impacted by estimated reserve quantities.
Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality differentials, and basis differentials, applicable to each period to our net share of estimated quantities of proved reserves remaining to be produced as of the end of that period. Expected cash flows are discounted to present value using an appropriate discount rate. For example, the standardized measure of discounted future net cash flows calculation requires that a 10 percent discount rate be applied. Although reserve estimates are inherently imprecise and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves. We engage Ryder Scott, an independent reservoir evaluation consulting firm, to audit a minimum of 80 percent of our total calculated proved reserve PV-10. We expect proved reserve estimates will change as additional information becomes available and as commodity prices and operating and capital costs change. We evaluate and estimate our proved reserves each year end. It should not be assumed that the standardized measure of discounted future net cash flows (GAAP) or PV-10 (non-GAAP) as of December 31, 2025, is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based these measures on the unweighted arithmetic average of the first-day-of-the-month price of each month within the trailing 12-month period ended December 31, 2025. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimates. Refer to Risk Factors in Part I, Item 1A of this report for additional discussion.
If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, which would reduce future net income. Changes in DD&A rate calculations caused by changes in reserve quantities are made prospectively. In addition, a decline in reserve estimates may impact the outcome of our assessment of proved and unproved properties for impairment. Impairments are recorded in the period in which they are identified.
The following table presents information about proved reserve changes from period to period due to items we do not control, such as price, and from changes due to production history and well performance. These changes do not require a capital expenditure on our part, but may have resulted from capital expenditures we incurred to develop other estimated proved reserves.
For the Years Ended December 31,
2025 2024
MMBOE Change
Revisions resulting from performance
(19.2) (8.0)
Removal of net proved undeveloped reserves no longer in our five-year development plan (40.7) (30.5)
Revisions resulting from price changes 3.7 (13.4)
Total (56.2) (51.9)
____________________________________________
Note: Amounts may not calculate due to rounding.
As previously noted, commodity prices are volatile and estimates of reserves are inherently imprecise. Consequently, we expect to continue experiencing these types of changes.
We cannot reasonably predict future commodity prices, although we believe that together, the analyses below provide reasonable information regarding the impact of changes in pricing and trends on total estimated net proved reserves. The following table reflects the estimated MMBOE change and percentage change to our total reported estimated net proved reserve volumes from the described hypothetical changes:
For the year ended December 31, 2025
MMBOE Change Percentage Change
10 percent decrease in SEC pricing (1)
(18.4) (3) %
Average NYMEX strip pricing as of fiscal year end (2)
(9.0) (1) %
10 percent decrease in net proved undeveloped reserves (3)
(26.1) (4) %
____________________________________________
(1) The change solely reflects the impact of a 10 percent decrease in SEC pricing to the total reported estimated net proved reserve volumes as of December 31, 2025, and does not include additional impacts to our estimated net proved reserves that may result from our internal intent to drill hurdles or changes in future service or equipment costs.
(2) The change solely reflects the impact of replacing SEC pricing with the five-year average NYMEX strip pricing as of December 31, 2025, and does not include additional impacts to our estimated net proved reserves that may result from our internal intent to drill hurdles or changes in future service or equipment costs. As of December 31, 2025, SEC pricing was $65.34 per Bbl for oil, $3.39 per MMBtu for gas, and $27.45 per Bbl for NGLs, and five-year average NYMEX strip pricing was $58.72 per Bbl for oil, $3.71 per MMBtu for gas, and $22.85 per Bbl for NGLs.
(3) The change solely reflects a 10 percent decrease in net proved undeveloped reserves as of December 31, 2025, and does not include any additional impacts to our estimated net proved reserves.
Additional reserve information can be found in Reservesin Part I, Items 1 and 2 of this report, and in Supplemental Oil and Gas Information (unaudited)in Part II, Item 8 of this report.
Impairment of Proved Properties. Proved oil and gas properties are evaluated for impairment on a depletion pool-by-pool basis and reduced to fair value when there is an indication that their carrying amount may not be recoverable. We estimate the expected future cash flows of our proved oil and gas properties and compare these undiscounted cash flows to the carrying amount to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the proved oil and gas properties to fair value (or discounted future cash flows). Management estimates future cash flows from all proved reserves and risk adjusted probable and possible reserves using various factors, which are subject to our judgment and expertise, and include, but are not limited to, commodity price forecasts, estimated future operating and capital costs, development plans, and discount rates to incorporate the risk and current market conditions associated with realizing the expected cash flows. We cannot predict when or if future impairment charges will be recorded because of the uncertainty in the factors discussed above. Despite any amount of future impairment being difficult to predict, based on our commodity price assumptions as of
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.
Accounting Matters
Refer to Recently Issued Accounting GuidanceinNote 1 - Summary of Significant Accounting Policiesin Part II, Item 8 of this report for information on new authoritative accounting guidance.
Environmental
We believe we are in substantial compliance with environmental laws and regulations and do not currently anticipate that material future expenditures will be required under the existing regulatory framework. However, environmental laws and regulations are subject to frequent changes, and we are unable to predict the impact that compliance with future laws or regulations, such as those currently being considered as discussed below, may have on future capital expenditures, liquidity, and results of operations.
Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. For additional information about hydraulic fracturing and related environmental matters, refer to Risk Factors - Risks Related to Litigation and Government Regulations - Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Climate Change and Air Quality. In June 2013, President Obama announced a Climate Action Plan designed to further reduce GHG emissions and prepare the nation for the physical effects that may occur as a result of climate change. The Climate Action Plan targeted methane reductions from the oil and gas sector as part of a comprehensive interagency methane strategy. As part of the Climate Action Plan, on May 12, 2016, the EPA issued final regulations applicable to new, modified, or reconstructed sources that amended and expanded 2012 regulations for the oil and gas sector by, among other things, setting emission limits for volatile organic compounds ("VOCs" or "VOC") and methane, a GHG, and added requirements for previously unregulated sources. The 2016 NSPS requires reduction of methane and VOCs from certain activities in oil and gas production, processing, transmission and storage and applies to facilities constructed, modified, or reconstructed after September 18, 2015. The regulation requires, among other things, GHG and VOC emission limits for certain equipment, such as centrifugal compressors and reciprocating compressors; semi-annual leak detection and repair for well sites and quarterly for boosting and garnering compressor stations and gas transmission compressor stations; control requirements and emission limits for pneumatic pumps; and additional requirements for control of GHGs and VOCs from well completions. In September 2020, the EPA finalized amendments to the 2012 and 2016 NSPS that removed transmission and storage infrastructure from regulation of methane emissions and other VOCs, as well as removed methane control requirements. The portion of the 2020 amendments that removed the transmission and storage infrastructure from the regulations was disapproved by the Congressional Review Act in 2021. In November 2021, the EPA proposed to expand the requirements of the 2012 and 2016 NSPS and also include requirements for states to develop performance standards to control methane emissions from existing sources. In December 2022, the EPA issued a supplemental proposal to update, strengthen, and expand the 2021 proposed rules. The EPA finalized the rule in December 2023. In March 2024, the EPA announced a final rule that implemented a waste emissions charge and new reporting requirements for facilities and wells completed after May 7, 2024. On March 14, 2025, President Trump signed a joint resolution of disapproval under the Congressional Review Act, voiding the EPA's final rule on methane waste emission, and in July 2025, the EPA announced an interim final rule that extends deadlines for certain provisions related to facilities and wells.
States are also required to comply with the NAAQS. The oil and gas sector is often subjected to additional controls when areas within states are not attaining the ozone NAAQS as the VOCs emitted by the oil and gas sector are a precursor to ozone formation. The ozone NAAQS was set at 70 parts per billion ("ppb") in 2015. In 2023, the EPA announced its plan to perform a full and complete review of the ozone NAAQS. The results of this review could result in changes to the ozone NAAQS which, if lowered, may result in additional actions by states requiring further emission controls and associated costs. Oil and gas facilities operating in areas that are determined to be out of compliance with the 70 ppb requirement or a lowered ozone NAAQS may be subject to increased emission controls and associated costs of compliance. In March of 2025, the EPA announced it was revisiting the Biden PM2.5 NAAQS and that it was planning on releasing guidance to increase flexibility of NAAQS implementation, reforms to the New Source Review, and direction on permitting obligations.
The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and many of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. In addition, certain international agreements seek to limit and reduce GHGs globally, including the Global Methane Pledge announced at the United Nations Climate Change Conference in Glasgow that aims to reduce methane emissions by 30 percent compared with 2020 levels.
The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and
thereby reduce demand for, the oil and gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition, and results of operations. Judicial challenges to new regulatory measures are likely and we cannot predict the outcome of such challenges. New regulatory suspensions, revisions, or rescissions and conflicting state and federal regulatory mandates may inhibit our ability to accurately forecast the costs associated with future regulatory compliance. Finally, scientists have concluded that increasing concentrations of GHGs in the earth's atmosphere produce climate changes that likely have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. Such effects could have an adverse effect on our financial condition and results of operations.
In terms of opportunities, the regulation of GHG emissions and the introduction of alternative incentives, such as enhanced oil recovery, carbon sequestration, and low carbon fuel standards, could benefit us in a variety of ways. For example, although federal regulation and climate change legislation could reduce the overall demand for the oil and gas that we produce, the relative demand for gas may increase because the burning of gas produces lower levels of emissions than other readily available fossil fuels such as oil and coal. In addition, if renewable resources such as wind or solar power become more prevalent, gas-fired electric plants may provide an alternative backup to maintain consistent electricity supply. Also, if states adopt low-carbon fuel standards, gas may become a more attractive transportation fuel. For the years ended December 31, 2025, and 2024, approximately 33 percent and 37 percent, respectively, of our production on a per BOE basis was gas. Market-based incentives for the capture and storage of carbon dioxide in underground reservoirs, particularly in oil and gas reservoirs, could also benefit us through the potential to obtain GHG emission allowances or offsets from or government incentives for the sequestration of carbon dioxide. For additional information about climate change, air quality, and related environmental matters, refer to Risk Factors - Risks Related to Litigation and Government Regulations - Legislative and regulatory initiatives and litigation related to global warming and climate change could have an adverse effect on our operations and the demand for oil, gas, and NGLs, and could result in significant litigation, capital, and related expenses andFederal and state regulatory initiatives relating to air quality and greenhouse gas emissions could result in increased costs and additional operating restrictions or delays.
Non-GAAP Financial Measures
Adjusted EBITDAX represents net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, and amortization expense, exploration expense, property abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, and certain other items. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we believe provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Agreement. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our revolving credit facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failed to comply with the covenants that establish a maximum permitted ratio of total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX, we would be in default, an event that would prevent us from borrowing under our revolving credit facility and would therefore materially limit a significant source of our liquidity. In addition, if we are in default under our revolving credit facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures governing each series of our outstanding Senior Notes would be entitled to exercise all of their remedies for default. Refer to Note 5 - Long-Term Debtin Part II, Item 8 of this report, for definition of and further detail about our Credit Agreement.
The following table provides reconciliations of our net income (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented:
For the Years Ended December 31,
2025 2024
(in millions)
Net income (GAAP) $ 648 $ 770
Interest expense 173 141
Interest income (3) (32)
Income tax expense 182 196
Depletion, depreciation, and amortization
1,207 809
Exploration (1)
51 59
Stock-based compensation expense 29 25
Net derivative gain (178) (50)
Net derivative settlement gain 132 69
Other, net 14 -
Adjusted EBITDAX (non-GAAP) 2,255 1,987
Interest expense (173) (141)
Interest income 3 32
Income tax expense (182) (196)
Exploration (1) (2)
(51) (50)
Amortization of deferred financing costs
10 7
Deferred income taxes 178 175
Other, net (42) (44)
Net change in working capital 13 11
Net cash provided by operating activities (GAAP) $ 2,011 $ 1,783
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Note: Prior year amounts may not calculate due to rounding.
(1) Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.
(2) For the year ended December 31, 2024, amount excludes certain capital expenditures related to one well deemed non-commercial.
SM Energy Company published this content on February 26, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on February 26, 2026 at 13:57 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]