SM Energy Company
05/07/2026 | Press release | Distributed by Public on 05/07/2026 06:56
Quarterly Report for Quarter Ending March 31, 2026 (Form 10-Q)
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 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 March 31, 2026, and the three months ended December 31, 2025 ("sequential quarterly" or "sequentially"), and the year-to-date ("YTD") change between the three months ended March 31, 2026, and the three months ended March 31, 2025 ("YTD 2026-over-YTD 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 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 creates a premier portfolio across the highest-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 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.
South Texas Divestiture
On April 30, 2026, we completed the South Texas Divestiture and received net cash proceeds of approximately $900 million, after preliminary purchase price adjustments and estimated selling costs. The final purchase price remains subject to customary post-closing adjustments. The South Texas Divestiture meaningfully advances our key priority of selling more than $1.0 billion in assets within one year of the completion of the Civitas Merger, which will enable 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 and subsequent to the first quarter of 2026, 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 Civitas 2028 Senior Notes. Concurrent with the completion of the South Texas Divestiture, we announced our intent to use the net cash proceeds to fully redeem our Civitas 2026 Senior Notes and 2026 Senior Notes at par, with planned redemption dates of May 11, 2026, and June 1, 2026, respectively. Our semi-annual borrowing base redetermination was completed subsequent to quarter end, reaffirming our borrowing base and aggregate lender commitments at their existing levels. As of March 31, 2026, we had no outstanding borrowings under our revolving credit facility.
General Overview
Our purpose. Our purpose is to improve communities with affordable, reliable energy. We are a premier operator of top-tier assets, 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.
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 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.
Market Trends and Uncertainties
During the first quarter of 2026, benchmark oil prices reached their highest levels since 2022, reflecting strong global demand and ongoing supply-side constraints resulting from recent geopolitical developments in the Middle East. Despite the resulting price volatility, we do not anticipate material changes to our 2026 development plan and we remain focused on our key priorities of post-Merger integration, maximizing free cash flow, and bolstering our balance sheet.
While benchmark gas prices increased sequentially, our realized gas prices during the three months ended March 31, 2026, were 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 widening basis differentials during the first quarter of 2026 and we expect these differentials to persist until additional pipeline capacity comes online in the region, which is anticipated in late 2026. In the DJ Basin, unfavorable differentials resulted from a different set of regional pressures, as a warm winter and spring shoulder season reduced demand while record-high production pushed storage inventories to record levels.
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 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. 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. 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 impairments of proved and unproved properties in the future. Future impairments of proved and unproved properties are difficult to predict, especially in a volatile price environment.
Areas of Operations
Our Permian Basin assets comprise approximately 229,000 net acres located in the Midland Basin and Delaware Basin of West Texas and New Mexico, (collectively referred to as the "Permian Basin"). Our acreage position in the Permian Basin provides future development and exploration opportunities within multiple oil-rich intervals, including 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 303,000 net acres located primarily in northeastern Colorado ("DJ Basin") and provide future development and exploration opportunities within multiple oil-rich intervals in the Niobrara and Codell formations, and includes acreage with light sweet crude oil and gas composition amenable to processing for NGL extraction.
As of March 31, 2026, our South Texas assets comprised approximately 155,000 net acres located in Dimmit and Webb counties, Texas ("South Texas"). Our overlapping acreage position in South Texas covered a significant portion of the western Eagle Ford shale and Austin Chalk formations, and included acreage across the oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction. Subsequent to March 31, 2026, we finalized the South Texas Divestiture, consisting of approximately 61,000 net acres, including the portion of our position located in the dry gas window. Refer to Note 2 - Mergers, Acquisitions, and Divestitures in Part I, Item 1 of this report for additional information.
Our Uinta Basin assets comprise approximately 62,000 net acres in northeastern Utah ("Uinta Basin") and provide future development and exploration opportunities within multiple oil-rich intervals in the Lower Green River and Wasatch formations, and include acreage with waxy crude and gas composition amenable to processing for NGL extraction.
First Quarter 2026 Overview and Outlook for the Remainder of 2026
During the first quarter of 2026:
•We completed the Civitas Merger on January 30, 2026, and made meaningful progress on post-Merger integration, advancing key operational and organizational initiatives, and capturing synergies. Integration remains a key priority.
•We issued the 2034 Senior Notes and used the majority of the net proceeds to repurchase $894 million in aggregate principal amount of the Civitas 2028 Senior Notes, excluding premiums paid, through the Tender Offer, of which $110 million settled subsequent to March 31, 2026.
•We announced our South Texas Divestiture, which subsequently closed on April 30, 2026.
•Our Board of Directors approved an increase to our fixed dividend policy to $0.88 per share annually, paid in quarterly increments beginning in the first quarter of 2026.
Refer to Note 2 - Mergers, Acquisitions, and Divestitures 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 110 percent sequentially to $1.5 billion for the three months ended March 31, 2026, compared with $703 million for the three months ended December 31, 2025. This increase was driven by a 79 percent sequential quarterly increase in average daily equivalent production to 371.2 MBOE and a 20 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 107 percent sequentially to $428 million for the three months ended March 31, 2026, compared with $207 million for the three months ended December 31, 2025. The sequential quarterly increases in production revenue, production expense, and average net daily equivalent production are primarily due to the inclusion of approximately two months of activity from the assets acquired in the Civitas Merger.
We recorded a net derivative loss of $697 million and a net derivative gain of $71 million for the three months ended March 31, 2026, and December 31, 2025, respectively. The net derivative loss during the first quarter 2026 resulted from rising oil prices primarily driven by the U.S.-Iran war, which began in late February 2026 and has significantly disrupted oil supply and shipping through the Strait of Hormuz. Included within these amounts are a net derivative settlement loss of $30 million and a net derivative settlement gain of $46 million for the three months ended March 31, 2026, and December 31, 2025, respectively.
Operational and financial activities during the three months ended March 31, 2026, resulted in the following:
•A net loss of $335 million, or $1.68 per diluted share, compared with net income of $109 million, or $0.95 per diluted share, for the three months ended December 31, 2025, primarily driven by a $697 million net derivative loss resulting from an increase in the forward oil price curves underlying our commodity derivative contracts as of March 31, 2026. Of this net derivative loss, $667 million relates to commodity derivative contracts that are scheduled to settle after March 31, 2026.
•Net cash provided by operating activities of $640 million, compared with $452 million for the three months ended December 31, 2025. The increase in net cash provided by operating activities was primarily due to the inclusion of two months of operating activity from assets acquired in the Civitas Merger.
•Adjusted EBITDAX, a non-GAAP financial measure, of $970 million, compared with $509 million for the three months ended December 31, 2025. The increase in adjusted EBITDAX was primarily due to the inclusion of two months of operating activity from the assets acquired in the Civitas Merger. Refer to the caption Non-GAAP Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations to net income (loss) 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 March 31, 2026, and December 31, 2025, and Between the Three Months Ended March 31, 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 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 months ended March 31, 2026, costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $725 million. 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 averaged six drilling rigs and two completion crews during the first 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 117 percent to 182.6 MBOE, reflecting the inclusion of two months of production from the Civitas assets acquired on January 30, 2026. Costs incurred during the three months ended March 31, 2026, totaled $336 million, or 46 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 between one and two drilling rigs during the first 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 was 81.4 MBOE for the three months ended March 31, 2026, reflecting the inclusion of two months of production from the Civitas assets acquired on January 30, 2026. Costs incurred during the three months ended March 31, 2026, totaled $113 million, or 16 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 two drilling rigs and one completion crew during the first quarter of 2026, and our operations focused primarily on the development and further delineation of the Austin Chalk formation. Average net daily equivalent production decreased sequentially by 15 percent to 68.0 MBOE. Costs incurred during the three months ended March 31, 2026, totaled $120 million, or 17 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 on our retained South Texas acreage, focused primarily on developing the Austin Chalk formation.
In our Uinta Basin program, we operated three drilling rigs and one completion crew during the first quarter of 2026, and our operations focused on delineation and development. Average net daily equivalent production decreased sequentially by eight percent to 39.1 MBOE. Costs incurred during the three months ended March 31, 2026, totaled $105 million, or 15 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 months ended March 31, 2026:
|
Permian Basin
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DJ Basin
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South Texas (1)
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Uinta Basin
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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 (2)
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40 | 33 | 43 | 41 | - | - | - | - | 83 | 74 | |||||||||||||||||||||||||||||||||||||||||||||||||
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Wells drilled(3)
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31 | 28 | 16 | 15 | 12 | 12 | 11 | 7 | 70 | 62 | |||||||||||||||||||||||||||||||||||||||||||||||||
|
Wells completed(3)
|
(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 | |||||||||||||||||||||||||||||||||||||||||||||||||
____________________________________________
(1) Subsequent to March 31, 2026, we divested 10 gross (10 net) drilled but not completed wells as part of the South Texas Divestiture.
(2) We acquired these drilled but not completed wells as part of the Civitas Merger on January 30, 2026.
(3) All drilling and completion activity related to the acquired assets in Permian Basin and DJ Basin occurred after the Closing Date of the Merger.
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 amounts include activity related to the assets acquired in the Civitas Merger, which is reflected only for the portion of the quarter occurring after January 30, 2026.
| For the Three Months Ended | |||||||||||||||||
| March 31, 2026 | December 31, 2025 | March 31, 2025 | |||||||||||||||
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Permian Basin Net Production:
|
|||||||||||||||||
| Oil (MMBbl) | 9.3 | 4.8 | 4.7 | ||||||||||||||
| Gas (Bcf) | 37.4 | 17.4 | 16.0 | ||||||||||||||
| NGLs (MMBbl) | 0.9 | - | - | ||||||||||||||
| Equivalent (MMBOE) | 16.4 | 7.7 | 7.3 | ||||||||||||||
| Average net daily equivalent (MBOE per day) | 182.6 | 84.2 | 81.5 | ||||||||||||||
| Relative percentage | 49 | % | 40 | % | 41 | % | |||||||||||
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DJ Basin Net Production:
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|||||||||||||||||
| Oil (MMBbl) | 3.4 | - | - | ||||||||||||||
| Gas (Bcf) | 15.6 | - | - | ||||||||||||||
| NGLs (MMBbl) | 1.3 | - | - | ||||||||||||||
| Equivalent (MMBOE) | 7.3 | - | - | ||||||||||||||
| Average net daily equivalent (MBOE per day) | 81.4 | - | - | ||||||||||||||
| Relative percentage | 22 | % | - | % | - | % | |||||||||||
| South Texas Net Production: | |||||||||||||||||
| Oil (MMBbl) | 1.4 | 1.8 | 1.7 | ||||||||||||||
| Gas (Bcf) | 16.3 | 18.6 | 17.6 | ||||||||||||||
| NGLs (MMBbl) | 2.0 | 2.5 | 2.4 | ||||||||||||||
| Equivalent (MMBOE) | 6.1 | 7.4 | 7.0 | ||||||||||||||
| Average net daily equivalent (MBOE per day) | 68.0 | 79.9 | 77.4 | ||||||||||||||
| Relative percentage | 18 | % | 39 | % | 39 | % | |||||||||||
|
Uinta Basin Net Production:
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|||||||||||||||||
| Oil (MMBbl) | 3.0 | 3.4 | 3.0 | ||||||||||||||
| Gas (Bcf) | 3.0 | 3.4 | 2.8 | ||||||||||||||
| NGLs (MMBbl) | - | - | - | ||||||||||||||
| Equivalent (MMBOE) | 3.5 | 3.9 | 3.5 | ||||||||||||||
| Average net daily equivalent (MBOE per day) | 39.1 | 42.7 | 38.4 | ||||||||||||||
| Relative percentage | 11 | % | 21 | % | 20 | % | |||||||||||
| Total Net Production: | |||||||||||||||||
| Oil (MMBbl) | 17.1 | 10.0 | 9.3 | ||||||||||||||
| Gas (Bcf) | 72.4 | 39.4 | 36.4 | ||||||||||||||
| NGLs (MMBbl) | 4.2 | 2.5 | 2.4 | ||||||||||||||
| Equivalent (MMBOE) | 33.4 | 19.0 | 17.8 | ||||||||||||||
| Average net daily equivalent (MBOE per day) | 371.2 | 206.9 | 197.3 | ||||||||||||||
____________________________________________
Note: Amounts may not calculate due to rounding.
Refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2026, and December 31, 2025, and Between the Three Months Ended March 31, 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 | |||||||||||||||||
| March 31, 2026 | December 31, 2025 | March 31, 2025 | |||||||||||||||
| Oil (per Bbl): | |||||||||||||||||
| Average NYMEX contract monthly price | $ | 71.93 | $ | 59.14 | $ | 71.42 | |||||||||||
| Realized price | $ | 73.69 | $ | 58.17 | $ | 70.56 | |||||||||||
| Effect of oil net derivative settlements | $ | (4.13) | $ | 2.66 | $ | 0.31 | |||||||||||
| Gas: | |||||||||||||||||
| Average NYMEX monthly settle price (per MMBtu) | $ | 5.04 | $ | 3.55 | $ | 3.65 | |||||||||||
| Realized price (per Mcf) | $ | 1.72 | $ | 1.81 | $ | 3.30 | |||||||||||
| Effect of gas net derivative settlements (per Mcf) | $ | 0.55 | $ | 0.48 | $ | 0.20 | |||||||||||
| NGLs (per Bbl): | |||||||||||||||||
|
Average OPIS price (1)
|
$ | 26.41 | $ | 24.92 | $ | 31.29 | |||||||||||
| Realized price | $ | 21.58 | $ | 20.67 | $ | 25.86 | |||||||||||
| Effect of NGL net derivative settlements | $ | 0.17 | $ | 0.09 | $ | (0.99) | |||||||||||
____________________________________________
(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 April 23, 2026, and March 31, 2026:
| As of April 23, 2026 | As of March 31, 2026 | ||||||||||
| NYMEX WTI oil (per Bbl) | $ | 82.53 | $ | 81.14 | |||||||
| NYMEX Henry Hub gas (per MMBtu) | $ | 3.41 | $ | 3.59 | |||||||
| OPIS NGLs (per Bbl) | $ | 30.96 | $ | 30.58 | |||||||
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 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 for the three months ended March 31, 2026, and the preceding three quarters:
| For the Three Months Ended | |||||||||||||||||||||||
| March 31, | December 31, | September 30, | June 30, | ||||||||||||||||||||
| 2026 | 2025 | 2025 | 2025 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Net production (MMBOE) | 33.4 | 19.0 | 19.7 | 19.0 | |||||||||||||||||||
| Oil, gas, and NGL production revenue | $ | 1,477 | $ | 703 | $ | 811 | $ | 785 | |||||||||||||||
| Oil, gas, and NGL production expense | $ | 428 | $ | 207 | $ | 229 | $ | 224 | |||||||||||||||
|
Depletion, depreciation, and amortization
|
$ | 432 | $ | 319 | $ | 325 | $ | 293 | |||||||||||||||
| Exploration | $ | 26 | $ | 18 | $ | 12 | $ | 15 | |||||||||||||||
| General and administrative | $ | 174 | $ | 40 | $ | 39 | $ | 42 | |||||||||||||||
| Net income (loss) | $ | (335) | $ | 109 | $ | 155 | $ | 202 | |||||||||||||||
Selected Performance Metrics
| For the Three Months Ended | |||||||||||||||||||||||
| March 31, | December 31, | September 30, | June 30, | ||||||||||||||||||||
| 2026 | 2025 | 2025 | 2025 | ||||||||||||||||||||
| Average net daily equivalent production (MBOE per day) | 371.2 | 206.9 | 213.8 | 209.1 | |||||||||||||||||||
| Lease operating expense (per BOE) | $ | 6.25 | $ | 5.55 | $ | 5.67 | $ | 5.52 | |||||||||||||||
| Transportation costs (per BOE) | $ | 3.65 | $ | 3.67 | $ | 3.77 | $ | 4.13 | |||||||||||||||
| Production taxes as a percent of oil, gas, and NGL production revenue | 5.5 | % | 3.8 | % | 4.1 | % | 3.9 | % | |||||||||||||||
| Ad valorem tax expense (per BOE) | $ | 0.47 | $ | 0.23 | $ | 0.51 | $ | 0.54 | |||||||||||||||
|
Depletion, depreciation, and amortization (per BOE)
|
$ | 12.91 | $ | 16.73 | $ | 16.54 | $ | 15.40 | |||||||||||||||
| General and administrative (per BOE) | $ | 5.20 | $ | 2.10 | $ | 2.00 | $ | 2.21 | |||||||||||||||
____________________________________________
Note: Amounts may not calculate due to rounding.
Overview of Selected Production and Financial Information, Including Trends
| For the Three Months Ended | Amount Change Between the Three Months Ended |
Percent Change Between the Three Months Ended
|
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| March 31, 2026 | December 31, 2025 | March 31, 2025 |
March 31, 2026 & December 31, 2025
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March 31, 2026 & 2025
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March 31, 2026 & December 31, 2025
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March 31, 2026 & 2025
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Net production volumes: (1)
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| Oil (MMBbl) | 17.1 | 10.0 | 9.3 | 7.2 | 7.8 | 72 | % | 84 | % | ||||||||||||||||||||||||||||||||
| Gas (Bcf) | 72.4 | 39.4 | 36.4 | 33.0 | 36.0 | 84 | % | 99 | % | ||||||||||||||||||||||||||||||||
| NGLs (MMBbl) | 4.2 | 2.5 | 2.4 | 1.7 | 1.9 | 69 | % | 79 | % | ||||||||||||||||||||||||||||||||
| Equivalent (MMBOE) | 33.4 | 19.0 | 17.8 | 14.4 | 15.7 | 76 | % | 88 | % | ||||||||||||||||||||||||||||||||
|
Average net daily production: (1) (2)
|
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| Oil (MBbl per day) | 190.3 | 108.4 | 103.7 | 81.9 | 86.6 | 76 | % | 84 | % | ||||||||||||||||||||||||||||||||
| Gas (MMcf per day) | 804.1 | 428.3 | 404.2 | 375.8 | 400.0 | 88 | % | 99 | % | ||||||||||||||||||||||||||||||||
| NGLs (MBbl per day) | 46.9 | 27.1 | 26.2 | 19.8 | 20.6 | 73 | % | 79 | % | ||||||||||||||||||||||||||||||||
| Equivalent (MBOE per day) | 371.2 | 206.9 | 197.3 | 164.3 | 173.9 | 79 | % | 88 | % | ||||||||||||||||||||||||||||||||
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Oil, gas, and NGL production revenue (in millions): (1)
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| Oil production revenue | $ | 1,262 | $ | 580 | $ | 658 | $ | 682 | $ | 604 | 118 | % | 92 | % | |||||||||||||||||||||||||||
| Gas production revenue | 124 | 71 | 120 | 53 | 4 | 75 | % | 3 | % | ||||||||||||||||||||||||||||||||
| NGL production revenue | 91 | 52 | 61 | 40 | 30 | 77 | % | 49 | % | ||||||||||||||||||||||||||||||||
| Total oil, gas, and NGL production revenue | $ | 1,477 | $ | 703 | $ | 840 | $ | 775 | $ | 637 | 110 | % | 76 | % | |||||||||||||||||||||||||||
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Oil, gas, and NGL production expense (in millions): (1)
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| Lease operating expense | $ | 209 | $ | 106 | $ | 109 | $ | 103 | $ | 100 | 98 | % | 92 | % | |||||||||||||||||||||||||||
| Transportation costs | 122 | 70 | 70 | 52 | 52 | 74 | % | 75 | % | ||||||||||||||||||||||||||||||||
| Production taxes | 81 | 27 | 37 | 54 | 44 | 202 | % | 120 | % | ||||||||||||||||||||||||||||||||
| Ad valorem tax expense | 16 | 4 | 10 | 11 | 6 | 254 | % | 60 | % | ||||||||||||||||||||||||||||||||
| Total oil, gas, and NGL production expense | $ | 428 | $ | 207 | $ | 225 | $ | 221 | $ | 203 | 107 | % | 90 | % | |||||||||||||||||||||||||||
| Realized price: | |||||||||||||||||||||||||||||||||||||||||
| Oil (per Bbl) | $ | 73.69 | $ | 58.17 | $ | 70.56 | $ | 15.52 | $ | 3.13 | 27 | % | 4 | % | |||||||||||||||||||||||||||
| Gas (per Mcf) | $ | 1.72 | $ | 1.81 | $ | 3.30 | $ | (0.09) | $ | (1.58) | (5) | % | (48) | % | |||||||||||||||||||||||||||
| NGLs (per Bbl) | $ | 21.58 | $ | 20.67 | $ | 25.86 | $ | 0.91 | $ | (4.28) | 4 | % | (17) | % | |||||||||||||||||||||||||||
| Per BOE | $ | 44.22 | $ | 36.92 | $ | 47.29 | $ | 7.30 | $ | (3.07) | 20 | % | (6) | % | |||||||||||||||||||||||||||
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Per BOE data: (1)
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| Oil, gas, and NGL production expense: | |||||||||||||||||||||||||||||||||||||||||
| Lease operating expense | $ | 6.25 | $ | 5.55 | $ | 6.13 | $ | 0.70 | $ | 0.12 | 13 | % | 2 | % | |||||||||||||||||||||||||||
| Transportation costs | 3.65 | 3.67 | 3.92 | (0.02) | (0.27) | (1) | % | (7) | % | ||||||||||||||||||||||||||||||||
| Production taxes | 2.43 | 1.41 | 2.07 | 1.02 | 0.36 | 72 | % | 17 | % | ||||||||||||||||||||||||||||||||
| Ad valorem tax expense | 0.47 | 0.23 | 0.55 | 0.24 | (0.08) | 104 | % | (15) | % | ||||||||||||||||||||||||||||||||
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Total oil, gas, and NGL production expense (1)
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$ | 12.80 | $ | 10.86 | $ | 12.68 | $ | 1.94 | $ | 0.12 | 18 | % | 1 | % | |||||||||||||||||||||||||||
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Depletion, depreciation, and amortization
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$ | 12.91 | $ | 16.73 | $ | 15.20 | $ | (3.82) | $ | (2.29) | (23) | % | (15) | % | |||||||||||||||||||||||||||
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General and administrative (3)
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$ | 5.20 | $ | 2.10 | $ | 2.22 | $ | 3.10 | $ | 2.98 | 148 | % | 134 | % | |||||||||||||||||||||||||||
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Net derivative settlement gain (loss) (4)
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$ | (0.90) | $ | 2.39 | $ | 0.44 | $ | (3.29) | $ | (1.34) | (138) | % | (305) | % | |||||||||||||||||||||||||||
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Earnings per share information (in millions, except per share data): (5)
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| Basic weighted-average common shares outstanding | 199 | 115 | 115 | 84 | 84 | 73 | % | 73 | % | ||||||||||||||||||||||||||||||||
| Diluted weighted-average common shares outstanding | 199 | 115 | 115 | 84 | 84 | 73 | % | 73 | % | ||||||||||||||||||||||||||||||||
| Basic net income (loss) per common share | $ | (1.68) | $ | 0.95 | $ | 1.59 | $ | (2.63) | $ | (3.27) | (277) | % | (206) | % | |||||||||||||||||||||||||||
| Diluted net income (loss) per common share | $ | (1.68) | $ | 0.95 | $ | 1.59 | $ | (2.63) | $ | (3.27) | (277) | % | (206) | % | |||||||||||||||||||||||||||
______________________________________
(1) Amounts and percentage changes may not calculate due to rounding.
(2) Average net daily production is calculated as total production for the quarter divided by 90 days. The results for the three months ended March 31, 2026 reflect only two months of production from the assets acquired in the Civitas Merger.
(3) For the first quarter of 2026, G&A expense per BOE includes one-time Civitas Merger related integration costs. See below and refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2026, and December 31, 2025, and Between the Three Months Ended March 31, 2026, and 2025 for additional discussion.
(4) Net derivative settlements for the three months ended March 31, 2026, and 2025, are included within the net derivative loss line item in the accompanying statements of operations.
(5) Refer to Note 10 - Earnings Per Share in Part I, Item 1 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 the 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 our historical results. Results discussed below for the three months ended March 31, 2026, include Civitas operations after the Closing Date of January 30, 2026.
Average net daily equivalent production for the three months ended March 31, 2026, increased 79 percent sequentially and 88 percent YTD 2026-over-YTD 2025 primarily driven by production from assets acquired in the Civitas 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 20 percent sequentially primarily due to increases in benchmark oil prices. Our realized price on a per BOE basis decreased six percent YTD 2026-over-YTD 2025 primarily due to decreases in both benchmark NGL prices and realized gas prices due to unfavorable price differentials at Waha and CIG Rockies during the first quarter 2026. We recognized a net loss on the settlement of our commodity derivative contracts of $0.90 per BOE during the three months ended March 31, 2026, and net gains of $2.39 and $0.44 per BOE during the three months ended December 31, 2025, and March 31, 2025, respectively.
Lease operating expense ("LOE") per BOE increased 13 percent sequentially and two percent YTD 2026-over-YTD 2025 primarily reflecting the integration of the Civitas assets, which have a higher LOE per BOE profile relative to our pre-Merger asset base. 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 which included assets that historically had the lowest LOE per BOE in our portfolio. 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 as increases in transportation costs were in line with increases in production volumes. Transportation costs per BOE decreased seven 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 72 percent sequentially and 17 percent YTD 2026-over-YTD 2025, as a result of an increase in realized oil price and a higher production tax rate associated with the acquired DJ Basin assets. Our overall production tax rate was 5.5 percent, 3.8 percent, and 4.4 percent for the three months ended March 31, 2026, December 31, 2025, and March 31, 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 increased $0.24 sequentially and decreased $0.08 YTD 2026-over-YTD 2025, as a result of fluctuations in commodity prices which impact the expected valuation 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, which is generally driven by fluctuations in commodity prices, and varying tax policies across the different counties in which we operate.
DD&A expense per BOE decreased 23 percent sequentially and 15 percent YTD 2026-over-YTD 2025, primarily due to a lower overall depletion rate for our Permian Basin assets reflecting the new amortization base established upon the closing of the Merger, cessation of recognizing DD&A expense for certain of our South Texas assets following the classification as held for sale, and shifts in our production mix due to the integration of the Civitas assets. 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. For the full-year 2026, we expect DD&A expense on an absolute basis to increase, compared with 2025, primarily reflecting higher anticipated production volumes and our
expanded asset base. We expect DD&A rates on a per BOE to decrease due to a lower overall depletion rate as a result of the Civitas Merger.
G&A expense on a per BOE basis increased 148 percent sequentially and 134 percent YTD 2026-over-YTD 2025, primarily due to Civitas Merger related one-time costs and additional headcount resulting from the Merger. 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. Approximately $118 million of general and administrative expenses during the three months ended March 31, 2026, are considered one-time Civitas Merger integration costs. For the full-year 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 one-time integration costs with a majority of these costs expected to be incurred during the first half of 2026.
Basic and diluted weighted-average common shares outstanding each increased 73 percent sequentially and YTD 2026-over-YTD 2025, primarily as a result of shares issued in connection with the Civitas Merger. We recognized a net loss from continuing operations for the three months ended March 31, 2026, and therefore all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per common share. Refer to 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 March 31, 2026, and December 31, 2025, and Between the Three Months Ended March 31, 2026, and 2025 below for additional discussion of operating expenses.
Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2026, and December 31, 2025, and Between the Three Months Ended March 31, 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 March 31, 2026, and December 31, 2025:
| Average Net Equivalent Production Increase (Decrease) |
Oil, Gas, and NGL Production Revenue Increase (Decrease) |
Oil, Gas, and NGL Production Expense Increase (Decrease) |
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| (MBOE per day) | (in millions) | (in millions) | |||||||||||||||
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Permian Basin
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98.4 | $ | 436 | $ | 128 | ||||||||||||
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DJ Basin
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81.4 | 342 | 102 | ||||||||||||||
| South Texas | (11.9) | (11) | (9) | ||||||||||||||
| Uinta Basin | (3.6) | 8 | - | ||||||||||||||
| Total | 164.3 | $ | 775 | $ | 221 | ||||||||||||
__________________________________________
Note: Amounts may not calculate due to rounding.
Average net daily equivalent production increased 79 percent, and total realized price increased 20 percent, resulting in a 110 percent increase in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense increased 107 percent. The sequential quarterly increases in production revenue, production expense, and average net daily equivalent production are primarily due to the inclusion of approximately two months of activity from the assets acquired in the Civitas Merger in the first quarter of 2026.
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 three months ended March 31, 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) |
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| (MBOE per day) | (in millions) | (in millions) | |||||||||||||||
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Permian Basin
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101.1 | $ | 336 | $ | 113 | ||||||||||||
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DJ Basin
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81.4 | 342 | 102 | ||||||||||||||
| South Texas | (9.4) | (33) | (7) | ||||||||||||||
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Uinta Basin
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0.7 | (8) | (6) | ||||||||||||||
| Total | 173.9 | $ | 637 | $ | 203 | ||||||||||||
__________________________________________
Note: Amounts may not calculate due to rounding.
Average net daily equivalent production increased 88 percent, and was partially offset by a decrease in total realized price of six percent, resulting in a 76 percent increase in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense increased 90 percent. The YTD 2026-over-YTD 2025 increases in production revenue, production expense, and average net daily equivalent production are primarily due to the inclusion of approximately two months of activity from the assets acquired in the Civitas Merger in the first quarter of 2026.
Depletion, depreciation, and amortization
| For the Three Months Ended | |||||||||||||||||
| March 31, 2026 | December 31, 2025 | March 31, 2025 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Depletion, depreciation, and amortization | $ | 432 | $ | 319 | $ | 270 | |||||||||||
DD&A expense increased 35 percent sequentially and 60 percent YTD 2026-over-YTD 2025, primarily driven by higher production volumes due to the inclusion of assets from the Civitas Merger. These increases were partially offset by a lower overall depletion rate for our Permian assets reflecting the new amortization base established upon the closing of the Merger, and cessation of recognizing DD&A expense for certain of our South Texas assets following classification as held for sale.
Exploration
| For the Three Months Ended | |||||||||||||||||
| March 31, 2026 | December 31, 2025 | March 31, 2025 | |||||||||||||||
| (in millions) | |||||||||||||||||
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Exploration
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$ | 26 | $ | 18 | $ | 12 | |||||||||||
Exploration expense increased 44 percent sequentially and 117 percent YTD 2026-over-YTD 2025 due to increases in overhead as a result of the inclusion of assets from the Civitas Merger which closed in the first quarter 2026. 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 | |||||||||||||||||
| March 31, 2026 | December 31, 2025 | March 31, 2025 | |||||||||||||||
| (in millions) | |||||||||||||||||
| General and administrative | $ | 174 | $ | 40 | $ | 39 | |||||||||||
G&A expense increased 335 percent sequentially and 346 percent YTD 2026-over-YTD 2025, primarily due to Civitas Merger related one-time costs and additional headcount resulting from the Merger. These costs include one-time severance and retention payments; accelerated stock-compensation expense related to terminated employees; transition employee costs incurred; one-time systems integration, advisory, and legal expenses; as well as higher compensation expense due to increased headcount.
Approximately $118 million of general and administrative expense during the three months ended March 31, 2026, is considered one-time Civitas Merger integration cost.
Net derivative (gain) loss
| For the Three Months Ended | |||||||||||||||||
| March 31, 2026 | December 31, 2025 | March 31, 2025 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Net derivative (gain) loss | $ | 697 | $ | (71) | $ | 17 | |||||||||||
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. During the first quarter of 2026, we recorded a net derivative loss of $697 million primarily resulting from the increase in the forward oil price curves underlying our commodity derivative contracts as of March 31, 2026. 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 | |||||||||||||||||
| March 31, 2026 | December 31, 2025 | March 31, 2025 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Interest expense | $ | (113) | $ | (43) | $ | (44) | |||||||||||
Interest expense increased 163 percent sequentially and 157 percent YTD 2026-over-YTD 2025. These increases were primarily driven by interest expense attributable to the Civitas Senior Notes assumed in connection with the Civitas 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.
Income tax (expense) benefit
| For the Three Months Ended | |||||||||||||||||
| March 31, 2026 | December 31, 2025 | March 31, 2025 | |||||||||||||||
| (in millions, except tax rate) | |||||||||||||||||
| Income tax (expense) benefit | $ | 75 | $ | (32) | $ | (50) | |||||||||||
| Effective tax rate | 18.3 | % | 23.1 | % | 21.4 | % | |||||||||||
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 higher statutory tax rates. Our effective tax rate decreased five percent sequentially and three percent YTD 2026-over-YTD 2025. These decreases were primarily a result of a remeasurement expense adjustment to record a Merger-related cumulative state apportionment change to the Company's historical net deferred tax asset and liability balances which reduced the tax benefit that was recorded during the first quarter of 2026. The decrease in the tax rate was partially offset by the effect of estimated state revenue changes affecting the apportionment of taxable income to states with higher statutory tax rates, effect of projected claim of research and development ("R&D") credits, and tax deduction limitations on compensation of covered individuals.
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 three months ended March 31, 2026, we primarily funded our capital expenditures and return of capital program with cash flows from operating activities. For the remainder of 2026, we expect to fund our 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 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.
On April 30, 2026, we completed the South Texas Divestiture and received net cash proceeds of approximately $900 million, after preliminary purchase price adjustments and estimated selling costs. The final purchase price remains subject to customary post-closing adjustments. We expect to use these 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 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, 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 March 31, 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 Civitas Merger on January 30, 2026, the Company and its lenders entered into the Fourth Amendment to the Credit Agreement ("Fourth Amendment") 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. Subsequent to March 31, 2026, our lender group reaffirmed our borrowing base and aggregate lender commitments at existing amounts, after giving effect to the South Texas Divestiture. 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 March 31, 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 | |||||||||||||||||
| March 31, 2026 | December 31, 2025 | March 31, 2025 | |||||||||||||||
| (in millions) | |||||||||||||||||
|
Daily weighted-average revolving credit facility balance
|
$ | 4 | $ | 2 | $ | 121 | |||||||||||
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 April 23, 2026, March 31, 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 | |||||||||||||||||
| March 31, 2026 | December 31, 2025 | March 31, 2025 | |||||||||||||||
| Weighted-average interest rate | 8.6 | % | 7.4 | % | 7.5 | % | |||||||||||
| Weighted-average borrowing rate | 8.2 | % | 6.7 | % | 6.9 | % | |||||||||||
Our weighted-average interest and weighted-average borrowing rate each increased sequentially and YTD 2026-over-YTD 2025, primarily due to the assumption of the Civitas Senior Notes, the majority of which carry a higher average coupon rate than our Senior Notes outstanding prior to the completion of the Civitas Merger. Our weighted-average interest rate benefited from the amortization of the premiums on the Civitas Senior Notes, which were recorded based on the fair value of the Civitas Senior Notes on the Closing Date of the Civitas Merger. We expect our weighted-average interest rate and weighted-average borrowing rate to increase slightly for the full-year 2026 compared with 2025.
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 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 the three months ended March 31, 2026, we spent $555 million on capital expenditures. This amount differs from the costs incurred amount of $725 million for the three months ended March 31, 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 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 three months ended March 31, 2026, and 2025, we did not repurchase any shares of our common stock under the Stock Repurchase Program. As of March 31, 2026, $488 million was available under the Stock Repurchase Program for repurchases of our common stock through December 31, 2027.
During the three months ended March 31, 2026, we used cash proceeds from the issuance of our 2034 Senior Notes to fund the repurchase of $784 million of outstanding principal amount of the Civitas 2028 Senior Notes through the Tender Offer. In connection
with the Early Tendered Notes, we paid total consideration of $808 million, including net premiums, and paid $14 million of accrued interest. Subsequent to March 31, 2026, we repurchased an additional $110 million of outstanding principal amount of the Civitas 2028 Senior Notes, and we paid total consideration of $114 million including net premiums, and paid $2 million of accrued interest. Refer to Note 6 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
In February 2026, we announced a new stockholder return framework designed to balance the allocation of free cash flow between debt reduction and returning capital to stockholders. Under this framework, after funding our fixed dividend, we expect to allocate approximately 20 percent of remaining free cash flow to share repurchases and approximately 80 percent to debt reduction. As leverage and absolute debt levels decline, we expect to increase the proportion of free cash flow allocated to share repurchases.
During the three months ended March 31, 2026, and 2025, we paid $82 million and $23 million, respectively, in dividends to our stockholders. 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.
On April 30, 2026, we instructed the trustees under the 2026 Senior Notes and Civitas 2026 Senior Notes to issue notices of full redemption of the $819 million aggregate principal amount outstanding, plus accrued and unpaid interest, to the holders of such Senior Notes. We intend to use the proceeds from the South Texas Divestiture to redeem the Civitas 2026 Senior Notes on May 11, 2026 and the 2026 Senior Notes on June 1, 2026. Following these redemptions, we will have no remaining Senior Notes maturities in 2026.
Analysis of Cash Flow Changes Between the Three Months Ended March 31, 2026, and 2025
The following tables present changes in cash flows between the three months ended March 31, 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 Three Months Ended March 31, | Amount Change Between Periods | ||||||||||||||||
| 2026 | 2025 | ||||||||||||||||
| (in millions) | |||||||||||||||||
| Net cash provided by operating activities | $ | 640 | $ | 483 | $ | 157 | |||||||||||
Net cash provided by operating activities increased for the three months ended March 31, 2026, compared with the same period in 2025, primarily as a result of an increase of $339 million in cash received from oil, gas, and NGL production revenue net of transportation costs and production taxes and an increase of $48 million in cash received on settled derivative trades, partially offset by an increase of $104 million in cash paid for certain G&A expenses, a $101 million increase in cash paid for LOE and ad valorem taxes and an increase of $13 million of cash paid for interest. These changes are largely a result of the Civitas 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 Three Months Ended March 31, | Amount Change Between Periods | ||||||||||||||||
| 2026 | 2025 | ||||||||||||||||
| (in millions) | |||||||||||||||||
| Net cash used in investing activities | $ | (628) | $ | (429) | $ | (199) | |||||||||||
Net cash used in investing activities increased for the three months ended March 31, 2026, compared with the same period in 2025, primarily as a result of a $141 million increase in capital expenditures and $49 million of cash paid in connection with the Civitas Merger, net of cash acquired.
Financing activities
| For the Three Months Ended March 31, | Amount Change Between Periods | ||||||||||||||||
| 2026 | 2025 | ||||||||||||||||
| (in millions) | |||||||||||||||||
| Net cash provided by (used in) financing activities | $ | 69 | $ | (54) | $ | 123 | |||||||||||
Net cash provided by financing activities of $69 million for the three months ended March 31, 2026, primarily reflects net proceeds of $985 million from the issuance of our 2034 Senior Notes, offset by the use of $808 million of such proceeds to repurchase a portion of the Civitas 2028 Senior Notes at a premium through the Tender Offer, and $82 million of dividends paid to our stockholders.
Net cash provided by financing activities for the three months ended March 31, 2025, primarily related to net repayments of $31 million under our revolving credit facility and $23 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 March 31, 2026, our outstanding principal amount of fixed-rate debt totaled $7.8 billion, and we had no floating-rate debt outstanding. As of March 31, 2025, our outstanding principal amount of fixed-rate debt totaled $2.7 billion and our floating-rate debt outstanding totaled $38 million. 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.
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 three months ended March 31, 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 $126 million, $12 million, and $9 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the three months ended March 31, 2026, would have offset the declines in oil, gas, and NGL production revenue by approximately $59 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 March 31, 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 $338 million, $209 million, and $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 three months ended March 31, 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 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 Civitas 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 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 (loss) (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented:
| For the Three Months Ended | |||||||||||||||||
|
March 31, 2026 |
December 31, 2025 |
March 31, 2025 |
|||||||||||||||
| (in millions) | |||||||||||||||||
| Net income (loss) (GAAP) | $ | (335) | $ | 109 | $ | 182 | |||||||||||
| Interest expense | 113 | 43 | 44 | ||||||||||||||
| Income tax expense (benefit) | (75) | 32 | 50 | ||||||||||||||
| Depletion, depreciation, and amortization | 432 | 319 | 270 | ||||||||||||||
|
Exploration (1)
|
24 | 17 | 10 | ||||||||||||||
|
Stock-based compensation expense (2)
|
10 | 8 | 7 | ||||||||||||||
| Net derivative loss | 697 | (71) | 17 | ||||||||||||||
| Net derivative settlement gain (loss) | (30) | 46 | 8 | ||||||||||||||
|
Transaction and integration costs (3)
|
135 | 6 | - | ||||||||||||||
| Other, net | (1) | - | - | ||||||||||||||
| Adjusted EBITDAX (non-GAAP) | 970 | 509 | 589 | ||||||||||||||
| Interest expense | (113) | (43) | (44) | ||||||||||||||
| Income tax (expense) benefit | 75 | (32) | (50) | ||||||||||||||
|
Exploration (1)
|
(24) | (17) | (10) | ||||||||||||||
| Amortization of deferred financing costs and debt premiums | (5) | 2 | 3 | ||||||||||||||
|
Transaction and integration costs (3)
|
(120) | (6) | - | ||||||||||||||
| Deferred income tax expense (benefit) | (85) | 33 | 26 | ||||||||||||||
| Other, net | (27) | (22) | 1 | ||||||||||||||
| Net change in working capital | (31) | 28 | (32) | ||||||||||||||
| Net cash provided by operating activities (GAAP) | $ | 640 | $ | 452 | $ | 483 | |||||||||||
____________________________________________
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 three months ended March 31, 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 Civitas Merger and post-merger integration activities. For the three months ended March 31, 2026, these costs consisted of $118 million of one-time integration costs ($15 million of which is stock-based compensation), included in general and administrative expense in the accompanying statements of operations, and $17 million of one-time transaction costs, included in other operating expense in the accompanying statements of operations. For the three months ended December 31, 2025, these costs consisted entirely of one-time transaction costs.
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