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. Throughout the following discussion, we explain changes between the three months ended June 30, 2026, and the three months ended March 31, 2026 (“sequential quarterly” or “sequentially”), and the year-to-date (“YTD”) change between the six months ended June 30, 2026, and the six months ended June 30, 2025 (“YTD 2026-over-YTD 2025”).
Overview of the Company
General Overview
Our purpose. Our purpose is to improve communities by providing affordable, reliable energy. We are a premier operator of top-tier assets, utilizing state-of-the-art digital technology, data analytics, and artificial intelligence in our operations, and continually pursuing innovative ideas to optimize capital efficiency and well performance, while reducing our impact on shared natural resources and operating in an efficient, safe, and responsible manner.
Strategic vision and value creation. 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 West Texas and New Mexico; the DJ Basin of Northeast Colorado; the Maverick Basin of South Texas; and the Uinta Basin of Northeast Utah. 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, active portfolio management, 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 post-Merger integration; maintaining safe operations; delivering consistent operational execution; maximizing free cash flow; and bolstering our balance sheet.
Responsible operations and governance. 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 Operations and EHS 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.
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 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 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 enhances our premier portfolio across high-return U.S. shale basins, enabling the realization of operational efficiencies and cost synergies and providing opportunities for increased free cash flow to drive long-term differentiated stockholder value.
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 124 million shares to holders of Civitas common stock, representing 52 percent of the shares of SM Energy’s common stock outstanding immediately following 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.
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South Texas Divestiture
On April 30, 2026, we completed the South Texas Divestiture and received net cash proceeds of $896 million. The final purchase price remains subject to customary post-closing adjustments. The South Texas Divestiture substantially achieved our target of selling more than $1.0 billion in assets within one year of the completion of the Merger, which has enabled us to reduce debt and strengthen our capital structure. See Note 2 - Mergers, Acquisitions, and Divestitures in Part I, Item 1 of this report for additional discussion.
Debt Optimization
During the six months ended June 30, 2026, and into the subsequent period, we made meaningful progress toward strengthening our debt structure and addressing near-term maturities of certain of our Senior Notes. We issued our 2034 Senior Notes and used the majority of the net proceeds to repurchase $894 million in aggregate principal amount of our higher-coupon 2028 Civitas Senior Notes. After the completion of the South Texas Divestiture, we used the net cash proceeds to fully redeem our 2026 Civitas Senior Notes and our 2026 Senior Notes at par, on May 11, 2026, and June 1, 2026, respectively. Subsequent to June 30, 2026, on August 5, 2026, we instructed the trustee under the 2027 Senior Notes to issue a notice of full redemption of the $417 million aggregate principal amount outstanding, plus accrued and unpaid interest, and intend to complete such redemption on September 4, 2026. Our semi-annual borrowing base redetermination was completed in April 2026, reaffirming our borrowing base and aggregate lender commitments at their existing levels. As of June 30, 2026, we had no outstanding borrowings under our revolving credit facility.
Areas of Operations
Our oil-weighted, liquids-rich asset base spans four operating areas within the United States. Across all areas, gas composition is amenable to processing for NGL extraction, and each area provides future development and exploration opportunities within multiple proven formations.
Our Permian Basin assets comprise approximately 233,000 net acres located in the Midland Basin and Delaware Basin of West Texas and New Mexico (collectively referred to as the “Permian Basin”) with future development and exploration opportunities in the Spraberry, Wolfcamp, and Woodford formations in the Midland Basin; and the Avalon, Bone Spring, and Wolfcamp formations in the Delaware Basin.
Our DJ Basin assets comprise approximately 301,000 net acres located primarily in northeastern Colorado (“DJ Basin”) with future development and exploration opportunities in the Niobrara and Codell formations.
Following the completion of the South Texas Divestiture, our South Texas assets comprise approximately 95,000 net acres located in Dimmit and Webb counties, Texas (“South Texas”) with future development and exploration opportunities across our overlapping acreage position covering a portion of the western Eagle Ford shale and Austin Chalk formations.
Our Uinta Basin assets comprise approximately 99,000 net acres in northeastern Utah (“Uinta Basin”), including acreage in Utah previously reported as other non-core acreage that has been reclassified to the Uinta Basin, with future development and exploration opportunities in the Lower Green River and Wasatch formations.
Market Trends and Uncertainties
During the six months ended June 30, 2026, benchmark oil prices reached their highest levels since 2022, reflecting strong global demand and ongoing supply-side constraints resulting from geopolitical developments in the Middle East. Despite the resulting price volatility, we have not made material changes to our 2026 development plan and do not currently anticipate making material changes for the remainder of 2026.
Benchmark gas prices have been volatile throughout 2026, and our realized gas prices have been negatively impacted by basis differentials in both the Permian Basin and the DJ Basin. In the Permian Basin, gas gathering and takeaway capacity constraints contributed to significant basis differentials at the Waha hub throughout the first and second quarters of 2026, with differentials widening in April and May before narrowing in June. In June, additional pipeline capacity entered service and we expect additional pipeline capacity during the second half of 2026 to provide adequate takeaway capacity out of the Permian Basin. In the DJ Basin, unfavorable differentials at CIG Rockies persisted through the second quarter of 2026 as elevated storage inventories and continued spring shoulder season demand weakness kept regional prices below benchmark levels, with only modest improvement late in the second quarter as summer cooling demand increased.
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; Organization of the Petroleum Exporting Countries (“OPEC”) plus other non-OPEC oil producing countries (collectively referred to as “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 including restrictions in and closures of the Strait of Hormuz; tariffs and trade restrictions; the potential for economic recession in the U.S.; and
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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.
Historically, tariffs have led to increased costs for products exchanged in international trade, and have heightened global political tensions. Changes in the U.S. and international trade policies, including the imposition, modification, or repeal of tariffs, continue to contribute to economic and market uncertainty. In recent periods, U.S. tariff policies and related trade actions have shifted frequently, and retaliatory measures or additional policy changes by other countries remain possible, and could contribute to broader economic and market instability.
The timing and magnitude of future effects of the factors discussed above are inherently unpredictable and could have a material adverse effect on our business, financial condition, and results of operations to an extent we are unable to reasonably estimate. Declines in oil, gas, and NGL prices are difficult to predict in a volatile price environment and could lead to impairments of proved and unproved properties.
Second Quarter 2026 Overview and Outlook for the Remainder of 2026
During the second quarter of 2026:
•We continued to advance Merger integration efforts across key operational and organizational workstreams and made further progress on capturing synergies.
•We closed our South Texas Divestiture on April 30, 2026, and received net cash proceeds of $896 million.
•We redeemed the entire $400 million and $419 million aggregate principal amounts outstanding of our 2026 Civitas Senior Notes and 2026 Senior Notes, respectively, at par.
•We resumed activity under our Stock Repurchase Program by repurchasing and subsequently retiring 2.6 million shares of our common stock at a cost of $84 million, excluding excise taxes, commissions, and fees.
We subsequently announced that we instructed the trustee under the 2027 Senior Notes to issue a notice of full redemption of the $417 million aggregate principal amount outstanding to the holders of such notes.
Refer to Note 2 - Mergers, Acquisitions, and Divestitures, Note 5 - Equity, and Note 6 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
Financial and Operational Results. Oil, gas, and NGL production revenue increased 46 percent sequentially to $2.2 billion for the three months ended June 30, 2026, compared with $1.5 billion for the three months ended March 31, 2026. This increase was primarily driven by an 18 percent sequential quarterly increase in average daily equivalent production to 439.7 MBOE per day, reflecting a full quarter of production from the assets acquired in the Merger, and a 22 percent sequential quarterly increase in total realized price per BOE, before the effect of net derivative settlements (“realized price” or “realized prices”), resulting from increases in benchmark oil prices. Oil, gas, and NGL production expense increased 30 percent sequentially to $556 million for the three months ended June 30, 2026, compared with $428 million for the three months ended March 31, 2026.
We recorded a net derivative gain of $272 million and a net derivative loss of $697 million for the three months ended June 30, 2026, and March 31, 2026, respectively. Included within these amounts are net derivative settlement losses of $220 million and $30 million for the three months ended June 30, 2026, and March 31, 2026, respectively.
Operational and financial activities during the three months ended June 30, 2026, resulted in the following:
•Net income of $1.1 billion, or $4.46 per diluted share, compared with a net loss of $335 million, or $1.68 per diluted share, for the three months ended March 31, 2026.
•Net cash provided by operating activities of $1.1 billion, compared with $640 million for the three months ended March 31, 2026.
•Adjusted EBITDAX, a non-GAAP financial measure, of $1.4 billion, compared with $970 million for the three months ended March 31, 2026. Refer to the caption Non-GAAP Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations to net income and net cash provided by operating activities.
Refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2026, and March 31, 2026, and Between the Six Months Ended June 30, 2026, and 2025 below for additional discussion.
Operational Activities. Our capital program for 2026 is expected to be approximately $2.65 billion to $2.85 billion, excluding acquisitions. Our capital program remains focused on applying our strength in geosciences and development optimization to highly economic oil and liquids rich development projects in our areas of operations that support our priority of strategic inventory replacement
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and growth. Refer to Overview of Liquidity and Capital Resources below for discussion of how we expect to fund the remainder of our 2026 capital program.
During the three and six months ended June 30, 2026, costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $734 million and $1.5 billion, respectively. Total costs incurred includes activity in our core areas of operations, corporate charges incurred in exploration activities, and costs related to exploration efforts outside of our core areas of operation.
In our Permian Basin program, we operated an average of seven drilling rigs and one completion crew during the second quarter of 2026, and our operations focused on development optimization and delineation of our assets in the Midland Basin and Delaware Basin. Average net daily equivalent production increased sequentially by 28 percent to 233.5 MBOE per day, reflecting a full quarter of production from the assets acquired in the Merger, compared to two months of production included in the first quarter of 2026 following the Closing Date of the Merger. Costs incurred during the three months ended June 30, 2026, totaled $300 million, or 41 percent of our total costs incurred for the period. We anticipate operating an average of six drilling rigs and two completion crews for the remainder of 2026, focused on development of the Spraberry, Woodford, Bone Spring, Wolfcamp, and Avalon formations.
In our DJ Basin program, we operated two drilling rigs during the second quarter of 2026 and one completion crew for a portion of the quarter, and our operations focused primarily on delineation and development. Average net daily equivalent production increased sequentially by 46 percent to 118.8 MBOE per day reflecting a full quarter of production from the assets acquired in the Merger, compared to two months of production included in the first quarter of 2026 following the Closing Date of the Merger. Costs incurred during the three months ended June 30, 2026, totaled $178 million, or 24 percent of our total costs incurred for the period. We anticipate operating an average of one drilling rig and one completion crew for the remainder of 2026, focused on further development and delineation of the Niobrara and Codell formations.
In our South Texas program, we operated one drilling rig and averaged one completion crew during the second quarter of 2026, and our operations focused primarily on the development and further delineation of the Austin Chalk formation. The three months ended June 30, 2026, reflect only one month of activity related to the divested assets prior to April 30, 2026. Average net daily equivalent production decreased sequentially by 30 percent to 47.4 MBOE per day, primarily due to the South Texas Divestiture. Costs incurred during the three months ended June 30, 2026, totaled $133 million, or 18 percent of our total costs incurred for the period. We anticipate operating one drilling rig during the remainder of 2026 and averaging one completion crew through the end of the third quarter of 2026, focused primarily on developing the Austin Chalk formation.
In our Uinta Basin program, we operated two drilling rigs and one completion crew during the second quarter of 2026, and our operations focused on delineation and development. Average net daily equivalent production increased sequentially by two percent to 40.1 MBOE per day. Costs incurred during the three months ended June 30, 2026, totaled $123 million, or 17 percent of our total costs incurred for the period. We anticipate operating between two and three drilling rigs and one completion crew during the remainder of 2026, focused primarily on delineating and developing the Lower Green River and Wasatch formations.
The table below provides a quarterly summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs for the three and six months ended June 30, 2026:
Permian Basin DJ Basin South Texas Uinta Basin Total
Gross Net Gross Net Gross Net Gross Net Gross Net
Wells drilled but not completed at December 31, 2025 15 12 — — 25 24 38 28 78 64
Wells acquired (1) 40 33 43 41 — — — — 83 74
Wells drilled (2) 31 28 16 15 12 12 11 7 70 62
Wells completed (2) (26) (23) (25) (23) (12) (11) (12) (9) (75) (66)
Wells drilled but not completed at March 31, 2026 60 50 34 33 25 25 37 26 156 134
Wells drilled 44 37 22 18 11 9 10 6 87 70
Wells completed (48) (39) (12) (12) (13) (13) (9) (7) (82) (71)
Wells sold (3) — — — — (10) (10) — — (10) (10)
Other (4) — 1 — 1 — — — — — 2
Wells drilled but not completed at June 30, 2026 56 49 44 40 13 11 38 25 151 125
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(1) We acquired these drilled but not completed wells as part of the Merger on January 30, 2026.
(2) All drilling and completion activity related to the acquired assets in the Permian Basin and DJ Basin occurred after the Closing Date of the Merger.
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(3) On April 30, 2026, as part of the South Texas Divestiture, we sold 10 gross (10 net) drilled but not completed wells.
(4) Includes adjustments related to normal business activities, including working interest changes for existing drilled but not completed wells and wells completed during the second quarter of 2026. Working interest changes can result from divestitures, joint development agreements, farm-outs, and other activities.
Production Results. The table below presents the disaggregation of our net production volumes by product type for each of our assets for the periods presented. The Permian Basin and DJ Basin results include production from properties acquired in the Merger after the Closing Date of January 30, 2026.
For the Three Months Ended For the Six Months Ended
June 30, 2026 March 31, 2026 June 30, 2026 June 30, 2025
Permian Basin Net Production:
Oil (MMBbl) 11.5 9.3 20.9 9.6
Gas (Bcf) 50.2 37.4 87.6 32.2
NGLs (MMBbl) 1.3 0.9 2.2 —
Equivalent (MMBOE) 21.2 16.4 37.7 14.9
Average net daily equivalent (MBOE per day) 233.5 182.6 208.2 82.6
Relative percentage 53 % 49 % 51 % 41 %
DJ Basin Net Production:
Oil (MMBbl) 5.0 3.4 8.4 —
Gas (Bcf) 23.7 15.6 39.3 —
NGLs (MMBbl) 1.9 1.3 3.2 —
Equivalent (MMBOE) 10.8 7.3 18.1 —
Average net daily equivalent (MBOE per day) 118.8 81.4 100.2 —
Relative percentage 27 % 22 % 25 % — %
South Texas Net Production:
Oil (MMBbl) 1.3 1.4 2.6 3.5
Gas (Bcf) 9.8 16.3 26.1 34.3
NGLs (MMBbl) 1.4 2.0 3.5 4.8
Equivalent (MMBOE) 4.3 6.1 10.4 14.0
Average net daily equivalent (MBOE per day) 47.4 68.0 57.6 77.4
Relative percentage 11 % 18 % 14 % 38 %
Uinta Basin Net Production:
Oil (MMBbl) 3.1 3.0 6.1 6.8
Gas (Bcf) 3.1 3.0 6.1 6.1
NGLs (MMBbl) — — — —
Equivalent (MMBOE) 3.6 3.5 7.2 7.8
Average net daily equivalent (MBOE per day) 40.1 39.1 39.6 43.3
Relative percentage 9 % 11 % 10 % 21 %
Total Net Production:
Oil (MMBbl) 20.9 17.1 38.0 19.9
Gas (Bcf) 86.8 72.4 159.2 72.6
NGLs (MMBbl) 4.6 4.2 8.9 4.8
Equivalent (MMBOE) 40.0 33.4 73.4 36.8
Average net daily equivalent (MBOE per day) 439.7 371.2 405.7 203.2
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Note: Amounts may not calculate due to rounding.
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Refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2026, and March 31, 2026, and Between the Six Months Ended June 30, 2026, and 2025 below for 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 periods presented:
For the Three Months Ended
June 30, 2026 March 31, 2026 June 30, 2025
Oil (per Bbl):
Average NYMEX contract monthly price $ 92.79 $ 71.93 $ 63.74
Realized price $ 96.85 $ 73.69 $ 62.04
Effect of oil net derivative settlements $ (16.23) $ (4.13) $ 2.01
Gas:
Average NYMEX monthly settle price (per MMBtu) $ 2.90 $ 5.04 $ 3.44
Realized price (per Mcf) $ 0.17 $ 1.72 $ 2.15
Effect of gas net derivative settlements (per Mcf) $ 1.37 $ 0.55 $ 0.51
NGLs (per Bbl):
Average OPIS price (1) $ 31.33 $ 26.41 $ 26.99
Realized price $ 24.69 $ 21.58 $ 21.91
Effect of NGL net derivative settlements $ 0.14 $ 0.17 $ 0.01
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(1) 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.
Given the uncertainty surrounding commodity prices, War and Geopolitical Instability, and global financial markets, we expect benchmark prices for oil, gas, and NGLs to remain volatile for the foreseeable future. In addition to supply and demand fundamentals, 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. Additionally, our realized prices at local sales points have been and may continue to be affected by infrastructure capacity or outages in the areas of our operations and beyond. We cannot reasonably predict the timing or likelihood of any future volatility or the related impacts. Refer to Market Trends and Uncertainties above for additional discussion of factors impacting pricing.
The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of July 23, 2026, and June 30, 2026:
As of July 23, 2026 As of June 30, 2026
NYMEX WTI oil (per Bbl) $ 79.86 $ 68.16
NYMEX Henry Hub gas (per MMBtu) $ 3.25 $ 3.39
OPIS NGLs (per Bbl) $ 29.75 $ 26.54
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
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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 8 - Derivative Financial Instruments in Part I, Item 1 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 and selected performance metrics for the three months ended June 30, 2026, and the preceding three quarters.
Selected Production and Financial Information
For the Three Months Ended
June 30, March 31, December 31, September 30,
2026 2026 2025 2025
(in millions)
Net production (MMBOE) 40.0 33.4 19.0 19.7
Oil, gas, and NGL production revenue $ 2,156 $ 1,477 $ 703 $ 811
Oil, gas, and NGL production expense $ 556 $ 428 $ 207 $ 229
Depletion, depreciation, and amortization $ 592 $ 432 $ 319 $ 325
Exploration $ 21 $ 26 $ 18 $ 12
General and administrative $ 79 $ 174 $ 40 $ 39
Net income (loss) $ 1,071 $ (335) $ 109 $ 155
Selected Performance Metrics
For the Three Months Ended
June 30, March 31, December 31, September 30,
2026 2026 2025 2025
Average net daily equivalent production (MBOE per day) 439.7 371.2 206.9 213.8
Lease operating expense (per BOE) $ 6.71 $ 6.25 $ 5.55 $ 5.67
Transportation costs (per BOE) $ 3.57 $ 3.65 $ 3.67 $ 3.77
Production taxes as a percent of oil, gas, and NGL production revenue 6.1 % 5.5 % 3.8 % 4.1 %
Ad valorem tax expense (per BOE) $ 0.37 $ 0.47 $ 0.23 $ 0.51
Depletion, depreciation, and amortization (per BOE) $ 14.81 $ 12.91 $ 16.73 $ 16.54
General and administrative (per BOE) $ 1.98 $ 5.20 $ 2.10 $ 2.00
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Note: Amounts may not calculate due to rounding.
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Overview of Selected Production and Financial Information, Including Trends
For the Three Months Ended Amount Change Between Periods Percent Change Between Periods For the Six Months Ended Amount Change Between Periods Percent Change Between Periods
June 30, 2026 March 31, 2026 June 30, 2026 June 30, 2025
Net production volumes: (1)
Oil (MMBbl) 20.9 17.1 3.8 22 % 38.0 19.9 18.2 92 %
Gas (Bcf) 86.8 72.4 14.4 20 % 159.2 72.6 86.5 119 %
NGLs (MMBbl) 4.6 4.2 0.4 10 % 8.9 4.8 4.0 84 %
Equivalent (MMBOE) 40.0 33.4 6.6 20 % 73.4 36.8 36.6 100 %
Average net daily production: (1)
Oil (MBbl per day) 229.8 190.3 39.6 21 % 210.2 109.7 100.4 92 %
Gas (MMcf per day) 953.7 804.1 149.6 19 % 879.3 401.2 478.1 119 %
NGLs (MBbl per day) 51.0 46.9 4.1 9 % 48.9 26.6 22.3 84 %
Equivalent (MBOE per day) 439.7 371.2 68.6 18 % 405.7 203.2 202.5 100 %
Oil, gas, and NGL production revenue (in millions): (1)
Oil production revenue $ 2,026 $ 1,262 $ 764 61 % $ 3,288 $ 1,312 1,976 151 %
Gas production revenue 15 124 (109) (88) % 139 198 (59) (30) %
NGL production revenue 115 91 24 26 % 206 115 91 80 %
Total oil, gas, and NGL production revenue $ 2,156 $ 1,477 $ 679 46 % $ 3,633 $ 1,625 $ 2,008 124 %
Oil, gas, and NGL production expense (in millions): (1)
Lease operating expense $ 268 $ 209 $ 59 28 % $ 477 $ 214 $ 264 123 %
Transportation costs 143 122 21 17 % 265 148 117 79 %
Production taxes 131 81 50 62 % 212 67 145 217 %
Ad valorem tax expense 14 16 (2) (13) % 30 20 10 52 %
Total oil, gas, and NGL production expense $ 556 $ 428 $ 129 30 % $ 984 $ 449 $ 535 119 %
Realized price:
Oil (per Bbl) $ 96.85 $ 73.69 $ 23.16 31 % $ 86.43 $ 66.04 $ 20.39 31 %
Gas (per Mcf) $ 0.17 $ 1.72 $ (1.55) (90) % $ 0.88 $ 2.73 $ (1.85) (68) %
NGLs (per Bbl) $ 24.69 $ 21.58 $ 3.11 14 % $ 23.21 $ 23.85 $ (0.64) (3) %
Per BOE $ 53.86 $ 44.22 $ 9.64 22 % $ 49.48 $ 44.17 $ 5.31 12 %
Per BOE data: (1)
Oil, gas, and NGL production expense:
Lease operating expense $ 6.71 $ 6.25 $ 0.46 7 % $ 6.50 $ 5.81 $ 0.69 12 %
Transportation costs 3.57 3.65 (0.08) (2) % 3.61 4.03 (0.42) (10) %
Production taxes 3.25 2.43 0.82 34 % 2.88 1.82 1.06 58 %
Ad valorem tax expense 0.37 0.47 (0.10) (21) % 0.41 0.54 (0.13) (24) %
Total oil, gas, and NGL production expense (1) $ 13.90 $ 12.80 $ 1.10 9 % $ 13.40 $ 12.21 $ 1.19 10 %
Depletion, depreciation, and amortization $ 14.81 $ 12.91 $ 1.90 15 % $ 13.95 $ 15.30 $ (1.35) (9) %
General and administrative (2) $ 1.98 $ 5.20 $ (3.22) (62) % $ 3.44 $ 2.21 $ 1.23 56 %
Net derivative settlement gain (loss) (3) $ (5.50) $ (0.90) $ (4.60) (511) % $ (3.41) $ 1.29 $ (4.70) (364) %
Earnings per share information (in millions, except per share data): (4)
Basic weighted-average common shares outstanding 239 199 40 20 % 219 115 104 90 %
Diluted weighted-average common shares outstanding 240 199 41 21 % 220 115 105 91 %
Basic net income (loss) per common share $ 4.48 $ (1.68) $ 6.16 367 % $ 3.35 $ 3.35 $ — — %
Diluted net income (loss) per common share $ 4.46 $ (1.68) $ 6.14 365 % $ 3.34 $ 3.34 $ — — %
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Note: Results for the three and six months ended June 30, 2026, reflect activity from the assets acquired in the Merger only after the Closing Date of January 30, 2026, and reflect activity from the assets sold in the South Texas Divestiture only for the period from January 1, 2026, through April 30, 2026.
(1) Amounts and percentage changes may not calculate due to rounding.
(2) G&A expense per BOE for the three and six months ended June 30, 2026, includes one-time Merger-related integration costs, the majority of which were incurred during the first quarter of 2026. See below and refer to Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2026, and March 31, 2026, and Between the Six Months Ended June 30, 2026, and 2025 for additional discussion.
(3) Net derivative settlements for the three months ended June 30, 2026, and for the six months ended June 30, 2026, and 2025, are included within the net derivative (gain) loss line item in the accompanying statements of operations.
(4) Refer to Note 10 - Earnings Per Share in Part I, Item 1 of this report for additional discussion.
The Merger, which closed on January 30, 2026, and the South Texas Divestiture, which closed on April 30, 2026, have materially affected our operating and financial results and will continue to affect comparability with prior periods. The addition of the Civitas assets and operations has increased production volumes and revenues and has impacted oil, gas, and NGL production expense, G&A expense, and other expense categories. The South Texas Divestiture also impacts comparability of our operating and financial results, as the three months ended June 30, 2026, reflect only one month of activity related to the divested assets prior to April 30, 2026. The magnitude and timing of ongoing impacts will depend, in part, on operating performance, commodity prices, Merger integration activities, and other factors and may not be directly comparable to our historical results.
Average net daily equivalent production for the three months ended June 30, 2026, increased 18 percent sequentially. The increase was primarily due to the inclusion of a full quarter of production from the assets acquired in the Merger, compared to two months of activity in the first quarter of 2026, partially offset by a decrease in production due to the South Texas Divestiture. Average net daily production increased 100 percent YTD 2026-over-YTD 2025 primarily driven by production from assets acquired in the Merger.
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 increased 22 percent sequentially primarily due to increases in benchmark oil prices, partially offset by decreases in realized gas prices driven by a decline in benchmark gas prices and widening price differentials at Waha. Our realized price on a per BOE basis increased 12 percent YTD 2026-over-YTD 2025 primarily due to increases in benchmark oil prices, partially offset by decreases in realized gas prices driven by unfavorable price differentials at Waha and CIG Rockies during the first half of 2026. We recognized net losses on the settlement of our commodity derivative contracts of $5.50 per BOE and $0.90 per BOE during the three months ended June 30, 2026, and March 31, 2026, respectively. During the six months ended June 30, 2026 and 2025, we recognized a net loss of $3.41 per BOE and a net gain of $1.29 per BOE, respectively.
Lease operating expense (“LOE”) per BOE increased seven percent sequentially and 12 percent YTD 2026-over-YTD 2025 primarily as a result of assets acquired in the Merger, which have a higher LOE per BOE profile relative to our pre-Merger asset base, with the sequential quarterly increase also reflecting a full quarter of contribution from the assets acquired in the Merger and a shift in production mix following the South Texas Divestiture. For the full-year 2026, we expect LOE per BOE to increase compared with 2025, driven by the inclusion of higher-cost acquired assets and a shift in production mix following the South Texas Divestiture. We expect to realize operational and cost synergies which will partially offset this increase. We anticipate volatility in LOE per BOE as a result of changes in production mix, timing of workover projects, changes in service provider costs, integration-related activities and broader industry conditions, all of which affect total LOE.
Transportation costs per BOE remained flat sequentially. Transportation costs per BOE decreased 10 percent YTD 2026-over-YTD 2025 primarily due to changes in our production mix. In general, we expect total transportation costs to fluctuate relative to changes in commodity and production mix across our areas of operations. For 2026, we expect transportation costs on a per BOE basis to remain relatively flat compared with 2025.
Production tax expense per BOE increased 34 percent sequentially and 58 percent YTD 2026-over-YTD 2025, primarily due to higher realized oil prices, and a higher production tax rate associated with our acquired DJ Basin assets relative to our pre-merger asset base, with the sequential increase also reflecting a full quarter of DJ Basin operations. Our overall production tax rate was 6.1 percent, 5.5 percent, and 3.9 percent for the three months ended June 30, 2026, March 31, 2026, and June 30, 2025, respectively. We expect that our Uinta Basin and South Texas assets will incur a lower production tax rate compared with our Permian Basin and DJ Basin assets. We generally expect production tax expense to correlate with oil, gas, and NGL production revenue. 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 per BOE decreased 21 percent sequentially and 24 percent YTD 2026-over-YTD 2025. We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis due to varying tax policies and assessment methodologies across the counties in which we operate, changes in our production mix, and fluctuations in commodity prices.
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DD&A expense per BOE increased 15 percent sequentially and decreased nine percent YTD 2026-over-YTD 2025, primarily due to the impacts of the Merger on DD&A rates, the South Texas Divestiture, and shifts in our production mix. For the full-year 2026, we expect DD&A expense on an absolute basis to increase compared with 2025 due to higher production volumes, while we expect DD&A expense to decrease on a per BOE basis. Our DD&A rate fluctuates as a result of changes in our production mix, changes in our total estimated net proved reserve volumes, changes in capital allocation, impairments, acquisition and divestiture activity, and carrying cost funding and sharing arrangements with third parties.
G&A expense on a per BOE basis decreased 62 percent sequentially primarily due to Merger-related one-time costs recognized during the three months ended March 31, 2026. G&A expense on a per BOE basis increased 56 percent YTD 2026-over-YTD 2025, primarily due to Merger-related one-time costs. These costs include one-time severance and retention payments; accelerated stock-compensation expense related to terminated employees; transition employee costs; one-time systems integration, advisory, and legal expenses; as well as higher compensation expense due to increased headcount. $155 million of G&A expense recognized during the six months ended June 30, 2026, is considered one-time Merger integration cost. For the full-year 2026, we expect G&A expense on an absolute basis to increase compared with 2025, primarily due to an increase in employee headcount as a result of the Merger, and one-time integration costs, with a majority of the one-time integration costs expected to be incurred during the first half of 2026. As one-time integration costs diminish and we realize the anticipated benefits of operational scale from the Merger, we expect G&A expense on a per BOE basis to decrease from current levels, though absolute G&A expense will reflect the scale of our combined operations and may be impacted by future business activities.
Basic and diluted weighted-average common shares outstanding increased sequentially and YTD 2026-over-YTD 2025, primarily as a result of shares issued in connection with the Merger, slightly offset by the repurchase of 2.6 million shares of our common stock under our Stock Repurchase Program. Refer to Note 5 - Equity and Note 10 - Earnings Per Share in Part I, Item 1 of this report for additional discussion.
Refer to Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2026, and March 31, 2026, and Between the Six Months Ended June 30, 2026, and 2025 below for additional discussion of operating expenses.
Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2026, and March 31, 2026, and Between the Six Months Ended June 30, 2026, and 2025
Refer to Overview of Selected Production and Financial Information, Including Trends above for additional discussion, including discussion of trends on a per BOE basis.
Average net daily equivalent production, production revenue, and production expense
Sequential Quarterly Changes. The following table presents 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 three months ended June 30, 2026, and March 31, 2026:
Average Net Equivalent Production Increase (Decrease) Oil, Gas, and NGL Production Revenue Increase (Decrease) Oil, Gas, and NGL Production Expense Increase (Decrease)
(MBOE per day) (in millions) (in millions)
Permian Basin 50.9 $ 381 $ 73
DJ Basin 37.3 237 64
South Texas (20.6) (19) (15)
Uinta Basin 1.0 80 6
Total 68.6 $ 679 $ 129
__________________________________________
Note: Amounts may not calculate due to rounding.
Average net daily equivalent production increased 18 percent, and total realized price increased 22 percent, resulting in a 46 percent increase in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense increased 30 percent. These increases are primarily due to the inclusion of a full quarter of activity from the assets acquired in the Merger during the second quarter of 2026, compared to two months of activity in the first quarter of 2026. These increases were partially offset by the South Texas Divestiture, which contributed one month of activity during the second quarter of 2026 compared to three months of activity during the first quarter of 2026. Production revenue also benefited from increases in benchmark oil prices.
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YTD 2026-over-YTD 2025 Changes. The following table presents 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 six months ended June 30, 2026, and 2025:
Average Net Equivalent Production Increase (Decrease) Oil, Gas, and NGL Production Revenue Increase (Decrease) Oil, Gas, and NGL Production Expense Increase (Decrease)
(MBOE per day) (in millions) (in millions)
Permian Basin 125.6 $ 1,104 $ 303
DJ Basin 100.2 921 269
South Texas (19.7) (63) (28)
Uinta Basin (3.6) 46 (9)
Total 202.5 $ 2,008 $ 535
__________________________________________
Note: Amounts may not calculate due to rounding.
Average net daily equivalent production increased 100 percent, and total realized price increased 12 percent, resulting in a 124 percent increase in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense increased 119 percent. These increases are primarily due to the inclusion of five months of activity from the assets acquired in the Merger during the six months ended June 30, 2026. These increases were partially offset by the South Texas Divestiture, which contributed four months of activity during the first half of 2026, compared to six months of activity during the first half of 2025. Production revenue also benefited from increases in benchmark oil prices.
Gain on divestiture activity
For the Three Months Ended For the Six Months Ended
June 30, 2026 March 31, 2026 June 30, 2026 June 30, 2025
(in millions)
Gain on divestiture activity $ 262 $ — $ 262 $ —
We recorded an estimated gain on divestiture activity of $262 million for the three and six months ended June 30, 2026, related to the South Texas Divestiture. Refer to Note 2 - Mergers, Acquisitions, and Divestitures in Part I, Item 1 of this report for additional discussion.
Other operating income
For the Three Months Ended For the Six Months Ended
June 30, 2026 March 31, 2026 June 30, 2026 June 30, 2025
(in millions)
Other operating income $ 82 $ 2 $ 84 $ 13
Other operating income increased $80 million sequentially and $71 million YTD 2026-over-YTD 2025 primarily due to a Texas natural gas severance tax refund recorded during the three months ended June 30, 2026.
Depletion, depreciation, and amortization
For the Three Months Ended For the Six Months Ended
June 30, 2026 March 31, 2026 June 30, 2026 June 30, 2025
(in millions)
Depletion, depreciation, and amortization $ 592 $ 432 $ 1,024 $ 563
DD&A expense increased 37 percent sequentially and 82 percent YTD 2026-over-YTD 2025 primarily due to higher production volumes and the impact of the Merger on DD&A rates.
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Exploration
For the Three Months Ended For the Six Months Ended
June 30, 2026 March 31, 2026 June 30, 2026 June 30, 2025
(in millions)
Exploration $ 21 $ 26 $ 47 $ 27
Exploration expense decreased 19 percent sequentially primarily due to a decrease in geological, geophysical, and other expenses. Exploration expense increased 74 percent YTD 2026-over-YTD 2025 due to increases in overhead as a result of the Merger. 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 Three Months Ended For the Six Months Ended
June 30, 2026 March 31, 2026 June 30, 2026 June 30, 2025
(in millions)
General and administrative $ 79 $ 174 $ 253 $ 81
G&A expense decreased 55 percent sequentially and increased 212 percent YTD 2026-over-YTD 2025, both primarily due to the timing of Merger-related one-time costs, the majority of which were incurred during the three months ended March 31, 2026. The YTD 2026-over-YTD 2025 increase also reflects higher compensation expense due to increased headcount resulting from the Merger. One-time costs of $155 million for the six months ended June 30, 2026, include severance and retention payments, accelerated stock-compensation expense related to terminated employees, transition employee costs, and systems integration, advisory, and legal expenses.
Net derivative (gain) loss
For the Three Months Ended For the Six Months Ended
June 30, 2026 March 31, 2026 June 30, 2026 June 30, 2025
(in millions)
Net derivative (gain) loss $ (272) $ 697 $ 425 $ (61)
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 8 - Derivative Financial Instruments in Part I, Item 1 of this report for additional discussion.
Interest expense
For the Three Months Ended For the Six Months Ended
June 30, 2026 March 31, 2026 June 30, 2026 June 30, 2025
(in millions)
Interest expense $ (111) $ (113) $ (224) $ (87)
Interest expense remained flat sequentially as decreases related to redeemed Senior Notes were mostly offset by increases related to issued Senior Notes and the inclusion of a full quarter of interest expense recorded during the three months ended June 30, 2026, related to our Civitas Senior Notes acquired in the Merger. Interest expense increased 157 percent YTD 2026-over-YTD 2025 primarily driven by interest expense attributable to our Civitas Senior Notes assumed in connection with the Merger. 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 the timing and amount of borrowings under our revolving credit facility.
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Income tax (expense) benefit
For the Three Months Ended For the Six Months Ended
June 30, 2026 March 31, 2026 June 30, 2026 June 30, 2025
(in millions, except tax rate)
Income tax (expense) benefit $ (318) $ 75 $ (243) $ (101)
Effective tax rate 22.9 % 18.3 % 24.8 % 20.8 %
Our effective tax rate is impacted by proportional effects of forecast net income on estimated permanent items between periods and estimated state revenue changes affecting the apportionment of taxable income to states with lower or higher statutory tax rates. Our effective tax rate increased five percentage points sequentially and increased four percentage points YTD 2026-over-YTD 2025. These increases were primarily a result of a remeasurement expense adjustment to record a Merger-related cumulative state apportionment change to our historical net deferred tax asset and liability balances which increased income tax expense during the first quarter of 2026. The same remeasurement expense adjustment decreased our effective tax rate during the three months ended March 31, 2026, due to the recorded income tax benefit for that period. The tax rate increases also include the effects of projected research and development (“R&D”) credit claims, and tax deduction limitations on compensation of covered individuals.
During the six months ended June 30, 2026, we made estimated payments, net of refunds received, of $25 million for federal income taxes and $7 million for state income taxes. In connection with IRC 382 analysis and state tax planning during the period, we are estimating more favorable utilization of tax attributes in 2026. As a result, the percent of estimated current federal and state income tax expense to the total income tax expense has decreased sequentially and YTD 2026-over-YTD 2025.
Refer to Note 4 - Income Taxes in Part I, Item 1 of this report, and to the Risk Factors section in Part 1, Item 1A of our 2025 Form 10-K for additional 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 short-term and long-term financial obligations, including 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
During the six months ended June 30, 2026, we primarily funded our capital expenditures and return of capital program with cash flows from operations. For the remainder of 2026, we expect to fund our capital expenditures, planned 2027 Senior Notes redemption, 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 the remainder of 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 certain existing stockholders and bondholders. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs.
During the first quarter of 2026, we issued our 2034 Senior Notes. See below for discussion on the use of net proceeds received, and refer to Note 6 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
During the second quarter of 2026, we completed the South Texas Divestiture and received net cash proceeds of $896 million subject to customary post-closing adjustments. We used the proceeds to reduce debt and strengthen our capital structure as further discussed under Uses of Cash below. See Note 2 - Mergers, Acquisitions, and Divestitures in Part I, Item 1 of this report for additional discussion.
Our credit ratings affect the availability of, and cost for us to borrow, additional funds. Any future downgrades in our credit ratings could make it more difficult or expensive for us to borrow additional funds. Two major credit rating agencies upgraded our credit ratings following the close of the 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.
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We have no control over the market prices for oil, gas, or 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 8 - Derivative Financial Instruments in Part I, Item 1 of this report for additional information about our commodity derivative contracts currently in place.
Credit Agreement
Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $5.0 billion. As of June 30, 2026, the borrowing base and aggregate revolving lender commitments under our Credit Agreement were $5.0 billion and $2.5 billion, respectively. In connection with the closing of the Merger on January 30, 2026, we entered into the Fourth Amendment with our lenders 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. 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 is scheduled to occur on October 1, 2026. 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. We were in compliance with all financial and non-financial covenants under the Credit Agreement as of June 30, 2026, and through the filing of this report.
The following table summarizes our daily weighted-average revolving credit facility balance during the periods presented:
For the Three Months Ended For the Six Months Ended
June 30, 2026 March 31, 2026 June 30, 2026 June 30, 2025
(in millions)
Daily weighted-average revolving credit facility balance $ 18 $ 4 $ 11 $ 93
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.
Refer to Note 6 - Long-Term Debt in Part I, Item 1 of this report for 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 July 23, 2026, June 30, 2026, and December 31, 2025.
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 and debt premiums. The amortization of deferred financing costs increases interest expense, while the amortization of debt premiums decreases interest expense. 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 periods presented:
For the Three Months Ended For the Six Months Ended
June 30, 2026 March 31, 2026 June 30, 2026 June 30, 2025
Weighted-average interest rate 7.5 % 8.6 % 7.6 % 7.5 %
Weighted-average borrowing rate 7.2 % 8.2 % 7.3 % 6.9 %
Our weighted-average interest and weighted-average borrowing rate each decreased sequentially due to the partial repayment of our 2028 Civitas Senior Notes and the full redemption of our 2026 Civitas Senior Notes and our 2026 Senior Notes. Our weighted-average interest and weighted-average borrowing rate each increased YTD 2026-over-YTD 2025, primarily due to the assumption of our Civitas Senior Notes, the majority of which carry a higher average coupon rate than our Senior Notes outstanding prior to the completion of the Merger. Our weighted-average interest rate benefited from the amortization of the premiums on our Civitas Senior Notes, which were recorded based on the fair value of our Civitas Senior Notes on the Closing Date of the Merger. We expect our weighted-average interest rate and weighted-average borrowing rate to increase slightly for the full-year 2026 compared with 2025.
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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 under 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.
Uses of Cash
We use cash for the development, exploration, and acquisition of oil and gas properties; for the payment of operating and G&A 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 the six months ended June 30, 2026, we spent $1.3 billion on capital expenditures. This amount differs from the costs incurred amount of $1.5 billion for the six months ended June 30, 2026, largely due to the timing of payments associated with accrued capital activity as costs incurred is an accrual-based amount that also includes asset retirement obligations, acquisitions of proved and unproved oil and gas properties, geological and geophysical expenses, and exploration overhead.
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. Our capital program for 2026 is expected to be approximately $2.65 billion to $2.85 billion, excluding acquisitions.
We may from time to time repurchase shares of our outstanding 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 (including pursuant to Rule 10b5-1 trading plans), 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.
Under our stockholder return framework announced in February 2026, we currently target approximately 20 percent of free cash flow, calculated on a quarterly basis and after dividend payments, for share repurchases, with the potential to repurchase in excess of this level as we execute on our scaled portfolio and benefit from a higher commodity price environment.
On May 11, 2026, we used cash proceeds from the South Texas Divestiture to redeem all $400 million aggregate principal amount outstanding of our 2026 Civitas Senior Notes, at par, and on June 1, 2026, we used the remaining proceeds to redeem all $419 million aggregate principal amount outstanding of our 2026 Senior Notes, at par. Following these redemptions, we have no remaining Senior Notes maturities in 2026. Please refer to Note 6 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
During the six months ended June 30, 2026, we used cash proceeds from the issuance of our 2034 Senior Notes to fund the repurchase of $894 million in aggregate principal amount of our 2028 Civitas Senior Notes through the Tender Offer. In connection with the Tender Offer, we paid total consideration of $922 million, including net premiums, and paid $16 million of accrued interest. Refer to Note 6 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
During the six months ended June 30, 2026, we repurchased and subsequently retired 2,643,506 shares of our common stock at a cost of $84 million, excluding excise taxes, commissions, and fees. During the six months ended June 30, 2025, we did not repurchase any shares of our common stock under the Stock Repurchase Program. As of June 30, 2026, $404 million was available under the Stock Repurchase Program for repurchases of our outstanding common stock through December 31, 2027.
During the six months ended June 30, 2026, and 2025, we paid $135 million and $46 million, respectively, in dividends to our stockholders. Beginning in the first quarter of 2026, dividends are 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 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.
On August 5, 2026, we instructed the trustee under our 2027 Senior Notes to issue a notice of full redemption of the $417 million aggregate principal amount outstanding, plus accrued and unpaid interest, to the holders of such notes. We intend to redeem our 2027 Senior Notes on September 4, 2026, using cash on hand. Following the redemption, we will have no remaining Senior Notes maturities in 2027.
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Analysis of Cash Flow Changes Between the Six Months Ended June 30, 2026, and 2025
The following tables present changes in cash flows between the six months ended June 30, 2026, and 2025, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying statements of cash flows in Part I, Item 1 of this report.
Operating activities
For the Six Months Ended June 30, Amount Change Between Periods
2026 2025
(in millions)
Net cash provided by operating activities $ 1,743 $ 1,054 $ 689
Net cash provided by operating activities increased for the six months ended June 30, 2026, compared with the same period in 2025, primarily as a result of an increase of $1.5 billion in cash received from oil, gas, and NGL production revenue net of transportation costs and production taxes, partially offset by a $290 million increase in cash paid for LOE and ad valorem taxes, a $219 million decrease in cash received on settled derivative trades, an increase of $139 million in cash paid for certain G&A expenses, and a $100 million increase in cash paid for interest. These changes are largely a result of the Merger. Net cash provided by operating activities is also affected by working capital changes and the timing of cash receipts and disbursements.
Investing activities
For the Six Months Ended June 30, Amount Change Between Periods
2026 2025
(in millions)
Net cash used in investing activities $ (485) $ (839) $ 354
Net cash used in investing activities decreased for the six months ended June 30, 2026, compared with the same period in 2025, primarily as a result of net cash proceeds of $896 million from the South Texas Divestiture, partially offset by a $485 million increase in capital expenditures and $49 million of cash paid in connection with the Merger, net of cash acquired.
Financing activities
For the Six Months Ended June 30, Amount Change Between Periods
2026 2025
(in millions)
Net cash used in financing activities $ (1,006) $ (113) $ (893)
Net cash used in financing activities of $1.0 billion for the six months ended June 30, 2026, primarily reflects $922 million, including repurchase premium, used to repurchase a portion of our 2028 Civitas Senior Notes through the Tender Offer, $819 million used to redeem our 2026 Civitas Senior Notes and the 2026 Senior Notes, and $135 million of dividends paid to our stockholders, partially offset by net proceeds of $984 million from the issuance of our 2034 Senior Notes.
Net cash used in financing activities for the six months ended June 30, 2025, primarily related to net repayments of $69 million under our revolving credit facility and $46 million of dividends paid to our stockholders.
Interest Rate Risk
We are exposed to market and credit risk due to the floating interest rate associated with any outstanding balance under 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 of 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 June 30, 2026, our outstanding principal amount of fixed-rate debt totaled $6.9 billion, and we had no floating-rate debt outstanding. As of June 30, 2025, our outstanding principal amount of fixed-rate debt totaled $2.7 billion and we had no floating-rate debt outstanding. Refer to Note 9 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion on the fair values of our Senior Notes.
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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, War and Geopolitical Instability, 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. The realized prices we receive at local sales points for our production have been and may continue to be affected by infrastructure capacity or outages in the areas of our operations and beyond, and also depend on numerous factors that are typically beyond our control. Based on our production for the six months ended June 30, 2026, a 10 percent decrease in our average realized oil, gas, and NGL prices would have reduced our oil, gas, and NGL production revenue by approximately $329 million, $14 million, and $21 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the six months ended June 30, 2026, would have offset the declines in oil, gas, and NGL production revenue by approximately $169 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 June 30, 2026, 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 $275 million, $121 million, and less than $1 million, respectively.
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”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.
We evaluate our transactions to determine if any variable interest entities exist. If we determine that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements. We have not been involved in any unconsolidated SPE transactions during the six months ended June 30, 2026, or through the filing of this report.
Critical Accounting Estimates
Refer to the corresponding section in Part II, Item 7 and to Note 1 - Summary of Significant Accounting Policies included in Part II, Item 8 of our 2025 Form 10-K for discussion of our accounting estimates. Additionally, the estimate discussed below was identified as critical to the understanding of our business and results of operations and required the application of significant management judgment during the year-to-date period covered by this report.
Purchase Price Allocation. Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities acquired based on their estimated fair value as of the acquisition date. Various assumptions are made when estimating fair values assigned to proved and unproved oil and gas properties including: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) risk adjustment factors; and (vi) a market participant-based weighted average cost of capital. These inputs require significant judgment by management at the time of the valuation.
Accounting Matters
Refer to Note 1 - Summary of Significant Accounting Policies in Part I, Item 1 of this report for information on new authoritative accounting guidance.
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, non-recurring or one-time costs including transaction and integration costs associated with the Merger, 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 based on adjusted EBITDAX ratios as further described in Note 5 - Long-Term Debt in the 2025 Form 10-K. 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
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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.
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 Three Months Ended For the Six Months Ended
June 30, 2026 June 30, 2025 June 30, 2026 June 30, 2025
(in millions)
Net income (GAAP) $ 1,071 $ 202 $ 736 $ 384
Interest expense 111 43 224 87
Income tax expense 318 51 243 101
Depletion, depreciation, and amortization 592 293 1,024 563
Exploration (1) 18 14 42 24
Stock-based compensation expense (2) 7 6 17 13
Net derivative (gain) loss (272) (78) 425 (61)
Net derivative settlement gain (loss) (220) 40 (250) 47
Gain on divestiture activity (262) — (262) —
Transaction and integration costs (3) 37 — 172 —
Other, net 6 — 5 1
Adjusted EBITDAX (non-GAAP) 1,406 570 2,376 1,158
Interest expense (111) (43) (224) (87)
Income tax expense (318) (51) (243) (101)
Exploration (1) (18) (14) (42) (24)
Amortization of deferred financing costs and debt premiums, net (5) 3 (10) 5
Transaction and integration costs (3) (32) — (152) —
Deferred income tax expense 316 43 231 69
Other, net (17) (6) (44) (5)
Net change in working capital (118) 69 (149) 38
Net cash provided by operating activities (GAAP) $ 1,103 $ 571 $ 1,743 $ 1,054
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Note: Prior year amounts may not calculate due to rounding.
(1) The exploration line item shown in the reconciliation above differs from the amount shown in the accompanying statements of operations because it excludes the portion of stock-based compensation expense recorded to exploration expense, which is separately presented in the stock-based compensation expense line item above.
(2) For the six months ended June 30, 2026, the stock-based compensation expense line item in the reconciliation above differs from the amount shown in the accompanying statements of cash flows because it excludes stock-based compensation expense included within the transaction and integration costs line item above.
(3) Transaction and integration costs include expenses associated with the Merger and post-Merger integration activities. For the three and six months ended June 30, 2026, these costs consisted of $37 million and $155 million, respectively, of one-time integration costs (including $5 million and $20 million, respectively, of stock-based compensation), which were included in G&A expense in the accompanying statements of operations, and less than $1 million and $17 million, respectively, of one-time transaction costs included in other operating expense in the accompanying statements of operations.
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