SM Energy Company

11/04/2026 | Press release | Distributed by Public on 11/04/2026 07:56

Quarterly Report for Quarter Ending September 30, 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 September 30, 2026, and the three months ended June 30, 2026 ("sequential quarterly" or "sequentially"), and the year-to-date ("YTD") change between the nine months ended September 30, 2026, and the nine months ended September 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, using state-of-the-art digital technology, data analytics, and artificial intelligence in our operations, and continually innovating to optimize capital efficiency and well performance, while reducing our impact on shared natural resources and operating efficiently, safely, and responsibly.
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 allocation, active portfolio management, and continued development and optimization, we seek to maximize returns and increase the long-term value of our asset portfolio.
Our long-term vision and strategy are focused on sustainably growing value for all of our stakeholders by maintaining and optimizing our high-quality asset portfolio, generating cash flows, and maintaining a 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 continuing to optimize operations across our multi-basin portfolio; maintaining safe operations; delivering consistent operational execution; maximizing free cash flow; and bolstering our balance sheet.
Responsible operations. We believe responsible operations and strong financial performance are mutually reinforcing. We are committed to operating safely and efficiently, managing environmental and operational risks, investing in our workforce, maintaining constructive relationships with the communities where we operate, and transparently reporting our performance. The Operations and Environmental, Health and Safety Committee of our Board of Directors assists the Board of Directors in overseeing operational performance, environmental stewardship, health and safety, sustainability reporting, and the management of operational and environmental risks. In addition, compensation for our executives and employees under certain aspects of our compensation plans is based in part on Company-wide performance metrics that include 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 asset 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.
South Texas Divestiture
On April 30, 2026, we completed the South Texas Divestiture. Subsequent to September 30, 2026, we completed the final post-closing settlement, resulting in total net cash proceeds of $894 million after final purchase price 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 nine months ended September 30, 2026, we strengthened our debt maturity profile and reduced higher-coupon debt through the following transactions:
•We issued our 2034 Senior Notes and used the majority of the net proceeds to repurchase $894 million in aggregate principal amount of certain of our higher-coupon 2028 Civitas Senior Notes.
•We used the net cash proceeds from the South Texas Divestiture to redeem, at par, all $819 million aggregate principal amount outstanding of our 2026 Civitas Senior Notes and our 2026 Senior Notes.
•We used cash flows from operations to redeem, at par, all $417 million aggregate principal amount outstanding of our 2027 Senior Notes.
As of September 30, 2026, we had no outstanding borrowings under our revolving credit facility. After these transactions, we have no Senior Notes maturities until mid-2028. Subsequent to September 30, 2026, we completed our semi-annual borrowing base redetermination, reaffirming our borrowing base and our aggregate lender commitments at their existing levels. See Note 6 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
Areas of Operations
Our oil-weighted, liquids-rich asset base spans four operating areas within the United States. Each area described below provides future development and exploration opportunities within multiple proven formations, and gas composition across all areas is amenable to processing for NGL extraction.
Our Permian Basin assets comprise approximately 230,000 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-Barnett formations in the Midland Basin; and the Avalon, Bone Spring, and Wolfcamp formations in the Delaware Basin.
Our DJ Basin assets comprise approximately 300,000 net acres located primarily in northeastern Colorado ("DJ Basin") with future development and exploration opportunities in the Niobrara and Codell formations.
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 nine months ended September 30, 2026, benchmark oil prices were substantially higher than the prior year period, primarily due to global supply disruptions and heightened risk associated with War and Geopolitical Instability. Despite sustained higher near-term prices, we have maintained our disciplined approach to capital allocation and have not materially altered our 2026 development program. We continue to monitor commodity market developments, including potential inflationary pressures on oilfield services, materials, and other key inputs associated with the elevated commodity price environment and the ongoing conflict in the Middle East.
Benchmark gas prices have fluctuated throughout 2026. Regional basis differentials in the Permian Basin and the DJ Basin have adversely impacted our realized gas prices, particularly during the first half of 2026. These differentials moderated during the third quarter, although regional pricing constraints continue to influence our realized prices. In the Permian Basin, gas gathering and takeaway capacity constraints contributed to widening basis differentials at the Waha hub during the first half of 2026, with differentials improving late in the second quarter and stabilizing in the third quarter of 2026 as new pipeline capacity entered service. We expect additional pipeline capacity to come online during the remainder of 2026 to further support takeaway out of the Permian Basin. In the DJ Basin, differentials at CIG Rockies widened during the first half of 2026, reflecting elevated regional storage following a mild winter,
as well as lower demand during the spring shoulder season. Differentials narrowed through the late second and third quarters as regional demand strengthened.
Commodity prices and broader financial markets continue to be influenced by geopolitical developments, global supply and demand fundamentals, production decisions by the Organization of the Petroleum Exporting Countries ("OPEC") plus other non-OPEC oil producing countries (collectively referred to as "OPEC+"), and broader economic and monetary conditions. The ongoing conflict in the Middle East, including disruptions to energy infrastructure and shipping routes such as the Strait of Hormuz, has contributed to elevated oil prices and increased uncertainty regarding future commodity market conditions.
These developments, together with evolving U.S. and international trade policies, including tariffs and other trade restrictions, may also contribute to inflationary pressures, supply chain disruptions, and increased costs for oilfield services, equipment, materials and other key inputs. We continue to monitor these conditions and their potential effects on our operating costs, capital expenditures, and development economics.
The duration and magnitude of these factors remain uncertain. Changes in commodity prices, regional pricing differentials, operating costs and broader economic conditions could materially affect our business, financial condition, and results of operations. In addition, sustained declines in oil, gas, and NGL prices could result in impairments of certain oil and gas properties.
Third Quarter 2026 Overview and Outlook for the Remainder of 2026
During the third quarter of 2026:
•We substantially completed the integration of the Merger across all key operational and organizational workstreams and have captured targeted synergies from our combined operations, with remaining integration activities expected to continue in the normal course.
•We redeemed the entire $417 million aggregate principal amount outstanding of our 2027 Senior Notes, at par.
•We repurchased and subsequently retired 2.3 million shares of our common stock at a cost of $81 million, excluding excise taxes, commissions, and fees.
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 remained relatively flat sequentially at $2.2 billion. Average net daily equivalent production decreased two percent sequentially to 433.1 MBOE per day for the three months ended September 30, 2026, compared with 439.7 MBOE per day for the three months ended June 30, 2026. This decrease reflects the impact of the divestiture of a portion of our South Texas assets which contributed one month of production in the prior quarter, partially offset by a net increase in average net daily equivalent production from our retained assets, including our retained South Texas assets. Total realized price per BOE, before the effect of net derivative settlements ("realized price" or "realized prices") increased slightly sequentially, as higher realized natural gas prices, resulting from narrower price differentials at Waha, and higher realized NGL prices were largely offset by lower benchmark oil prices. Oil, gas, and NGL production expense increased three percent sequentially to $574 million for the three months ended September 30, 2026, compared with $556 million for the three months ended June 30, 2026.
We recorded a net derivative loss of $684 million and a net derivative gain of $272 million for the three months ended September 30, 2026, and June 30, 2026, respectively. Included within these amounts are net derivative settlement losses of $207 million and $220 million for the three months ended September 30, 2026, and June 30, 2026, respectively.
Operational and financial activities during the three months ended September 30, 2026, resulted in the following:
•Net income of $93 million, or $0.39 per diluted share, compared with net income of $1.1 billion, or $4.46 per diluted share, for the three months ended June 30, 2026, which included an estimated gain of $262 million related to the South Texas Divestiture.
•Net cash provided by operating activities of $1.1 billion remained unchanged compared with the three months ended June 30, 2026.
•Adjusted EBITDAX, a non-GAAP financial measure, of $1.3 billion, compared with $1.4 billion for the three months ended June 30, 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 September 30, 2026, and June 30, 2026, and Between the Nine Months Ended September 30, 2026, and 2025 below for additional discussion.
Operational Activities. Our capital program for 2026 is expected to be approximately $2.75 billion, excluding acquisitions. We remain 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 and nine months ended September 30, 2026, costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $782 million and $2.2 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 six drilling rigs and two completion crews during the third quarter of 2026. Average net daily equivalent production decreased sequentially by five percent to 222.7 MBOE per day. Costs incurred during the three months ended September 30, 2026, totaled $394 million, or 50 percent of our total costs incurred for the period. We anticipate operating an average of six drilling rigs and an average of one completion crew for the remainder of 2026.
In our DJ Basin program, we operated one drilling rig and one completion crew during the third quarter of 2026. Average net daily equivalent production remained flat sequentially at 119.4 MBOE per day. Costs incurred during the three months ended September 30, 2026, totaled $145 million, or 19 percent of our total costs incurred for the period. We anticipate operating an average of one drilling rig for the remainder of 2026 and one completion crew for a portion of the fourth quarter of 2026.
In our South Texas program, we operated one drilling rig and averaged one completion crew during the third quarter of 2026. Average net daily equivalent production remained flat sequentially at 46.3 MBOE per day, despite the second quarter benefiting from one month of production from the divested South Texas assets. Costs incurred during the three months ended September 30, 2026, totaled $95 million, or 12 percent of our total costs incurred for the period. We anticipate operating one drilling rig and no completion crews for the remainder of 2026.
In our Uinta Basin program, we operated an average of two drilling rigs and one completion crew during the third quarter of 2026. Average net daily equivalent production increased sequentially by 12 percent to 44.7 MBOE per day. Costs incurred during the three months ended September 30, 2026, totaled $129 million, or 16 percent of our total costs incurred for the period. We anticipate operating an average of three drilling rigs and one completion crew during the remainder of 2026.
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 by quarter:
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
Wells drilled 37 29 11 8 7 7 9 7 64 51
Wells completed (33) (31) (25) (24) (6) (5) (14) (10) (78) (70)
Wells drilled but not completed at September 30, 2026 60 47 30 24 14 13 33 22 137 106
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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.
(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 certain existing drilled but not completed wells and for certain 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 Nine Months Ended
September 30, 2026 June 30,
2026 		September 30, 2026 September 30, 2025
Permian Basin Net Production:
Oil (MMBbl) 10.9 11.5 31.8 14.3
Gas (Bcf) 50.3 50.2 137.9 48.9
NGLs (MMBbl) 1.2 1.3 3.4 -
Equivalent (MMBOE) 20.5 21.2 58.2 22.5
Average net daily equivalent (MBOE per day) 222.7 233.5 213.1 82.4
Relative percentage 51 % 53 % 51 % 40 %
DJ Basin Net Production:
Oil (MMBbl) 5.2 5.0 13.6 -
Gas (Bcf) 22.7 23.7 62.0 -
NGLs (MMBbl) 2.0 1.9 5.2 -
Equivalent (MMBOE) 11.0 10.8 29.1 -
Average net daily equivalent (MBOE per day) 119.4 118.8 106.7 -
Relative percentage 28 % 27 % 26 % - %
South Texas Net Production:
Oil (MMBbl) 1.5 1.3 4.1 5.5
Gas (Bcf) 7.6 9.8 33.7 53.0
NGLs (MMBbl) 1.5 1.4 4.9 7.6
Equivalent (MMBOE) 4.3 4.3 14.7 22.0
Average net daily equivalent (MBOE per day) 46.3 47.4 53.8 80.4
Relative percentage 11 % 11 % 13 % 39 %
Uinta Basin Net Production:
Oil (MMBbl) 3.5 3.1 9.6 10.5
Gas (Bcf) 3.7 3.1 9.9 9.2
NGLs (MMBbl) - - - -
Equivalent (MMBOE) 4.1 3.6 11.3 12.0
Average net daily equivalent (MBOE per day) 44.7 40.1 41.3 44.0
Relative percentage 10 % 9 % 10 % 21 %
Total Net Production:
Oil (MMBbl) 21.2 20.9 59.2 30.3
Gas (Bcf) 84.4 86.8 243.5 111.1
NGLs (MMBbl) 4.6 4.6 13.5 7.6
Equivalent (MMBOE) 39.8 40.0 113.3 56.5
Average net daily equivalent (MBOE per day) 433.1 439.7 414.9 206.8
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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 September 30, 2026, and June 30, 2026, and Between the Nine Months Ended September 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, and the effect of net derivative settlements, for the periods presented:
For the Three Months Ended
September 30, 2026 June 30, 2026 September 30, 2025
Oil (per Bbl):
Average NYMEX contract monthly price $ 85.79 $ 92.79 $ 64.93
Realized price $ 85.76 $ 96.85 $ 63.83
Effect of oil net derivative settlements $ (11.84) $ (16.23) $ 1.57
Gas:
Average NYMEX monthly settle price (per MMBtu) $ 2.95 $ 2.90 $ 3.07
Realized price (per Mcf) $ 2.48 $ 0.17 $ 2.19
Effect of gas net derivative settlements (per Mcf) $ 0.51 $ 1.37 $ 0.58
NGLs (per Bbl):
Average OPIS price (1)
$ 31.64 $ 31.33 $ 25.58
Realized price $ 29.40 $ 24.69 $ 20.79
Effect of NGL net derivative settlements $ 0.04 $ 0.14 $ -
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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.
Commodity prices remain subject to uncertainty arising from global supply and demand fundamentals, geopolitical developments and broader economic conditions. While these factors influence benchmark prices, our realized prices are also affected by regional supply and demand, basis differentials, and transportation and infrastructure constraints, including capacity limitations and outages in or affecting our operating areas. We continue to monitor these conditions and their potential impacts on our realized prices and financial results. 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 October 22, 2026, and September 30, 2026:
As of October 22, 2026 As of September 30, 2026
NYMEX WTI oil (per Bbl) $ 90.76 $ 83.62
NYMEX Henry Hub gas (per MMBtu) $ 2.90 $ 3.08
OPIS NGLs (per Bbl) $ 36.25 $ 31.91
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. The volume of our expected production that we cover with commodity derivative contracts is determined by our balance sheet objectives, capital allocation priorities, anticipated development activity and associated capital requirements, and prevailing commodity market conditions, including available future prices and derivative structures. Our current commodity derivative contracts partially reduce our exposure to volatility in commodity prices and basis differentials in the near term. Our use of costless collars for a portion of our commodity derivative contracts 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 and selected performance metrics for the three months ended September 30, 2026, and the preceding three quarters.
Selected Production and Financial Information
For the Three Months Ended
September 30, June 30, March 31, December 31,
2026 2026 2026 2025
(in millions)
Net production (MMBOE) 39.8 40.0 33.4 19.0
Oil, gas, and NGL production revenue $ 2,160 $ 2,156 $ 1,477 $ 703
Oil, gas, and NGL production expense $ 574 $ 556 $ 428 $ 207
Depletion, depreciation, and amortization
$ 590 $ 592 $ 432 $ 319
Exploration $ 22 $ 21 $ 26 $ 18
General and administrative $ 56 $ 79 $ 174 $ 40
Net income (loss) $ 93 $ 1,071 $ (335) $ 109
Selected Performance Metrics
For the Three Months Ended
September 30, June 30, March 31, December 31,
2026 2026 2026 2025
Average net daily equivalent production (MBOE per day) 433.1 439.7 371.2 206.9
Lease operating expense (per BOE) $ 7.02 $ 6.71 $ 6.25 $ 5.55
Transportation costs (per BOE) $ 3.53 $ 3.57 $ 3.65 $ 3.67
Production taxes as a percent of oil, gas, and NGL production revenue 6.4 % 6.1 % 5.5 % 3.8 %
Ad valorem tax expense (per BOE) $ 0.38 $ 0.37 $ 0.47 $ 0.23
Depletion, depreciation, and amortization (per BOE)
$ 14.81 $ 14.81 $ 12.91 $ 16.73
General and administrative (per BOE) $ 1.40 $ 1.98 $ 5.20 $ 2.10
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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 Periods Percent Change Between Periods For the Nine Months Ended Amount Change Between Periods Percent Change Between Periods
September 30, 2026 June 30, 2026 September 30, 2026 September 30, 2025
Net production volumes: (1)
Oil (MMBbl) 21.2 20.9 0.3 1 % 59.2 30.3 28.9 95 %
Gas (Bcf) 84.4 86.8 (2.4) (3) % 243.5 111.1 132.4 119 %
NGLs (MMBbl) 4.6 4.6 - (1) % 13.5 7.6 5.9 77 %
Equivalent (MMBOE) 39.8 40.0 (0.2) - % 113.3 56.5 56.8 101 %
Average net daily production: (1)
Oil (MBbl per day) 230.2 229.8 0.3 - % 216.9 111.2 105.8 95 %
Gas (MMcf per day) 917.0 953.7 (36.7) (4) % 892.0 406.9 485.1 119 %
NGLs (MBbl per day) 50.1 51.0 (0.9) (2) % 49.3 27.8 21.5 77 %
Equivalent (MBOE per day) 433.1 439.7 (6.7) (2) % 414.9 206.8 208.1 101 %
Oil, gas, and NGL production revenue (in millions): (1)
Oil production revenue $ 1,816 $ 2,026 $ (210) (10) % $ 5,104 $ 1,981 $ 3,123 158 %
Gas production revenue 209 15 194 1,280 % 348 282 66 23 %
NGL production revenue 135 115 21 18 % 341 172 169 98 %
Total oil, gas, and NGL production revenue $ 2,160 $ 2,156 $ 5 - % $ 5,793 $ 2,436 $ 3,358 138 %
Oil, gas, and NGL production expense (in millions): (1)
Lease operating expense $ 280 $ 268 $ 11 4 % $ 757 $ 325 $ 432 133 %
Transportation costs 141 143 (2) (2) % 406 222 183 82 %
Production taxes 138 131 8 6 % 350 100 249 249 %
Ad valorem tax expense 15 14 1 3 % 45 30 15 51 %
Total oil, gas, and NGL production expense $ 574 $ 556 $ 18 3 % $ 1,558 $ 678 $ 880 130 %
Realized price:
Oil (per Bbl) $ 85.76 $ 96.85 $ (11.09) (11) % $ 86.19 $ 65.28 $ 20.91 32 %
Gas (per Mcf) $ 2.48 $ 0.17 $ 2.31 1,359 % $ 1.43 $ 2.54 $ (1.11) (44) %
NGLs (per Bbl) $ 29.40 $ 24.69 $ 4.71 19 % $ 25.33 $ 22.73 $ 2.60 11 %
Per BOE $ 54.23 $ 53.86 $ 0.37 1 % $ 51.15 $ 43.15 $ 8.00 19 %
Per BOE data: (1)
Oil, gas, and NGL production expense:
Lease operating expense $ 7.02 $ 6.71 $ 0.31 5 % $ 6.69 $ 5.76 $ 0.93 16 %
Transportation costs 3.53 3.57 (0.04) (1) % 3.58 3.94 (0.36) (9) %
Production taxes 3.47 3.25 0.22 7 % 3.09 1.78 1.31 74 %
Ad valorem tax expense 0.38 0.37 0.01 3 % 0.40 0.53 (0.13) (25) %
Total oil, gas, and NGL production expense $ 14.40 $ 13.90 $ 0.50 4 % $ 13.75 $ 12.01 $ 1.74 14 %
Depletion, depreciation, and amortization
$ 14.81 $ 14.81 $ - - % $ 14.25 $ 15.73 $ (1.48) (9) %
General and administrative (2)
$ 1.40 $ 1.98 $ (0.58) (29) % $ 2.72 $ 2.14 $ 0.58 27 %
Net derivative settlement gain (loss) (3)
$ (5.20) $ (5.50) $ 0.30 5 % $ (4.04) $ 1.53 $ (5.57) (364) %
Earnings per share information (in millions, except per share data): (4)
Basic weighted-average common shares outstanding 237 239 (2) (1) % 225 115 110 96 %
Diluted weighted-average common shares outstanding 239 240 (1) - % 226 115 111 97 %
Basic net income per common share $ 0.39 $ 4.48 $ (4.09) (91) % $ 3.67 $ 4.70 $ (1.03) (22) %
Diluted net income per common share $ 0.39 $ 4.46 $ (4.07) (91) % $ 3.66 $ 4.69 $ (1.03) (22) %
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Note: Results for the nine months ended September 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 nine months ended September 30, 2026, includes one-time Merger-related integration costs, the majority of which were incurred during the six months ended June 30, 2026. See below and refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2026, and June 30, 2026, and Between the Nine Months Ended September 30, 2026, and 2025 for additional discussion.
(3) Net derivative settlements for the three months ended September 30, 2026, and for the nine months ended September 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 with the nine months ended September 30, 2026, reflecting eight months of activity from the acquired assets. With respect to the South Texas Divestiture, the three months ended June 30, 2026, include one month of activity from the divested assets prior to the April 30, 2026 closing date, while the three months ended September 30, 2026, reflect only our retained South Texas assets. The nine months ended September 30, 2026, include four months of activity from the divested assets. The magnitude and timing of ongoing impacts will depend, in part, on operating performance, commodity prices, and other factors and may not be directly comparable to our historical results.
Average net daily equivalent production for the three months ended September 30, 2026, decreased two percent sequentially to 433.1 MBOE per day, compared with 439.7 MBOE per day for the three months ended June 30, 2026. This decrease reflects the impact of the divestiture of a portion of our South Texas assets which contributed one month of production in the prior quarter, partially offset by a net increase in average net daily equivalent production from our retained assets, including our retained South Texas assets. Average net daily production increased 101 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 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 slightly sequentially as higher realized natural gas prices, primarily resulting from narrower price differentials at Waha and higher realized NGL prices, were largely offset by lower benchmark oil prices. Our realized price on a per BOE basis increased 19 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. We recognized net losses on the settlement of our commodity derivative contracts of $5.20 per BOE and $5.50 per BOE during the three months ended September 30, 2026, and June 30, 2026, respectively. During the nine months ended September 30, 2026, and 2025, we recognized a net loss of $4.04 per BOE and a net gain of $1.53 per BOE, respectively.
Lease operating expense ("LOE") per BOE increased five percent sequentially, primarily due to the timing of workover activity and a shift in our geographic production mix toward higher-cost assets. LOE per BOE increased 16 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. 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 across our assets 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 geographic and commodity mix of our production, 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 nine percent YTD 2026-over-YTD 2025 primarily due to changes in our production mix across our assets as a result of the Merger and the South Texas Divestiture. We expect transportation costs to vary based on production volumes and commodity mix, contractual transportation agreements, applicable rates, and the utilization of transportation capacity across our operating areas. On a per BOE basis, we expect transportation costs for 2026 to decrease slightly compared with 2025.
Production tax expense per BOE increased seven percent sequentially, primarily due to higher production taxes attributable to our DJ Basin assets. Production tax expense per BOE increased 74 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. Our overall production tax rate was 6.4 percent, 6.1 percent, and 4.1 percent for the three months ended September 30, 2026, June 30, 2026, and September 30, 2025, respectively. Production taxes are primarily driven by oil, gas, and NGL revenues, with effective tax rates varying by jurisdiction based on applicable tax structures and available incentives. We generally expect our Uinta Basin and South Texas assets to incur lower production tax rates compared with our Permian and DJ Basin assets. Accordingly, changes in commodity prices, production volumes, and the geographic and commodity mix of our production may impact both total production tax expense and our production tax rate.
Ad valorem tax expense per BOE increased three percent sequentially and decreased 25 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 commodity and production mix across our assets, and fluctuations in commodity prices.
DD&A expense per BOE remained flat sequentially. DD&A expense per BOE 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 the geographic and commodity mix of our production, 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 29 percent sequentially, primarily due to a decrease in Merger-related one-time costs compared with the three months ended June 30, 2026. G&A expense on a per BOE basis increased 27 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; and higher compensation expense due to increased headcount. During the nine months ended September 30, 2026, we recognized $159 million of one-time Merger integration costs in G&A expense. 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, a majority of which were incurred during the first half of 2026.
Basic and diluted weighted-average common shares outstanding increased YTD 2026-over-YTD 2025, primarily as a result of shares issued in connection with the Merger, slightly offset by the repurchase of 4.9 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 September 30, 2026, and June 30, 2026, and Between the Nine Months Ended September 30, 2026, and 2025 below for additional discussion of operating expenses.
Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2026, and June 30, 2026, and Between the Nine Months Ended September 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 September 30, 2026, and June 30, 2026:
Average Net Equivalent Production Increase (Decrease) Oil, Gas, and NGL
Production Revenue
Increase (Decrease) 		Oil, Gas, and NGL
Production Expense
Increase
(MBOE per day) (in millions) (in millions)
Permian Basin
(10.8) $ (6) $ -
DJ Basin
0.6 - 2
South Texas (1.1) 4 2
Uinta Basin 4.6 7 14
Total (6.7) $ 5 $ 18
__________________________________________
Note: Amounts may not calculate due to rounding.
Average net daily equivalent production decreased two percent, as the three months ended June 30, 2026, included one month of production from our divested South Texas assets. Total realized price increased slightly, resulting in oil, gas, and NGL production revenue remaining relatively flat. Oil, gas, and NGL production expense increased three percent primarily driven by increases in LOE and production tax expense.
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 nine months ended September 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
130.7 $ 1,863 $ 485
DJ Basin
106.7 1,501 436
South Texas (26.6) (115) (52)
Uinta Basin
(2.7) 108 10
Total 208.1 $ 3,358 $ 880
__________________________________________
Note: Amounts may not calculate due to rounding.
Average net daily equivalent production increased 101 percent, and total realized price increased 19 percent, resulting in a 138 percent increase in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense increased 130 percent. These increases are primarily due to the inclusion of eight months of activity from the assets acquired in the Merger during the nine months ended September 30, 2026, and higher benchmark oil prices. These increases were partially offset by the divestiture of a portion of our South Texas assets, which contributed four months of activity during the nine months ended September 30, 2026, compared to a full nine months during the prior-year period.
Gain (loss) on divestiture activity
For the Three Months Ended For the Nine Months Ended
September 30, 2026 June 30, 2026 September 30, 2026 September 30, 2025
(in millions)
Gain (loss) on divestiture activity $ (2) $ 262 $ 260 $ -
During the nine months ended September 30, 2026, we recorded a gain on divestiture activity of $260 million 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 Nine Months Ended
September 30, 2026 June 30, 2026 September 30, 2026 September 30, 2025
(in millions)
Other operating income $ 12 $ 82 $ 96 $ 13
Other operating income decreased $70 million sequentially and increased $83 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 Nine Months Ended
September 30, 2026 June 30, 2026 September 30, 2026 September 30, 2025
(in millions)
Depletion, depreciation, and amortization $ 590 $ 592 $ 1,614 $ 888
DD&A expense remained flat sequentially. DD&A expense increased 82 percent YTD 2026-over-YTD 2025 primarily due to higher production volumes and the impact of the Merger on DD&A rates.
Exploration
For the Three Months Ended For the Nine Months Ended
September 30, 2026 June 30, 2026 September 30, 2026 September 30, 2025
(in millions)
Exploration
$ 22 $ 21 $ 69 $ 39
Exploration expense remained relatively flat sequentially. Exploration expense increased 77 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 Nine Months Ended
September 30, 2026 June 30, 2026 September 30, 2026 September 30, 2025
(in millions)
General and administrative $ 56 $ 79 $ 309 $ 121
G&A expense decreased 29 percent sequentially and increased 155 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 six months ended June 30, 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 $159 million for the nine months ended September 30, 2026, include severance and retention payments, accelerated stock-based 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 Nine Months Ended
September 30, 2026 June 30, 2026 September 30, 2026 September 30, 2025
(in millions)
Net derivative (gain) loss $ 684 $ (272) $ 1,109 $ (107)
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 Nine Months Ended
September 30, 2026 June 30, 2026 September 30, 2026 September 30, 2025
(in millions)
Interest expense $ (116) $ (111) $ (340) $ (130)
Interest expense increased 162 percent YTD 2026-over-YTD 2025 primarily driven by interest expense attributable to our Civitas Senior Notes assumed in connection with the Merger, partially offset by the refinancing of higher-coupon debt and redemptions of Senior Notes. 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
For the Three Months Ended For the Nine Months Ended
September 30, 2026 June 30, 2026 September 30, 2026 September 30, 2025
(in millions, except tax rate)
Income tax expense $ (30) $ (318) $ (273) $ (150)
Effective tax rate 24.9 % 22.9 % 24.8 % 21.7 %
Our effective tax rate for the three and nine months ended September 30, 2026, reflects the proportional effects of forecast net income on estimated permanent items between periods and state apportionment factors affecting the allocation of taxable income across jurisdictions with varying statutory tax rates. Our effective tax rate increased both sequentially and YTD 2026-over-YTD 2025, primarily due to changes in these factors. Additionally, the tax rates include the effects of projected research and development credit claims and tax deduction limitations on compensation of covered individuals.
During the nine months ended September 30, 2026, we made estimated payments, net of refunds received, of $25 million for federal income taxes and $5 million for state income taxes. Our IRC Section 382 analysis and state tax planning indicate that certain tax attributes are expected to be utilized in 2026. However, higher operating income limits the amount of tax attributes available to offset taxable income. Consequently, current federal and state income tax expense represents a greater percentage of total income tax expense both 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 I, Item 1A of our 2025 Form 10-K for additional discussion.
Overview of Liquidity and Capital Resources
Based on our current liquidity position, anticipated operating cash flows, and available sources of capital, we believe we have sufficient financial resources to execute our business plan and 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 commitments to maintain flexibility with regard to our activity level and capital expenditures.
Sources of Cash
During the nine months ended September 30, 2026, we primarily funded our capital expenditures, 2027 Senior Notes redemption, and return of capital program with cash flows from operations. 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.
During the second quarter of 2026, we completed the South Texas Divestiture. Subsequent to September 30, 2026, we completed the final post-closing settlement, resulting in total net cash proceeds of $894 million after final purchase price 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 liquidity sources can be affected by the broader economic environment, 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. 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. As of September 30, 2026, the borrowing base and aggregate revolving lender commitments under our Credit Agreement were $5.0 billion and $2.5 billion, respectively. The borrowing base is subject to regular, semi-annual redetermination, and considers the value of both our proved oil and gas properties reflected in our most recent reserve report and commodity derivative contracts, each as determined by our lender group. Subsequent to September 30, 2026, our lender group reaffirmed our borrowing base and aggregate lender commitments at existing levels. The next borrowing base redetermination is scheduled to occur on April 1, 2027. 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 September 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 Nine Months Ended
September 30, 2026 June 30, 2026 September 30, 2026 September 30, 2025
(in millions)
Daily weighted-average revolving credit facility balance
$ 32 $ 18 $ 18 $ 66
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, and the presentation of the outstanding balance, total amount of letters of credit, and available borrowing capacity under the Credit Agreement as of October 22, 2026, September 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 Nine Months Ended
September 30, 2026 June 30, 2026 September 30, 2026 September 30, 2025
Weighted-average interest rate 7.6 % 7.5 % 7.6 % 7.4 %
Weighted-average borrowing rate 7.3 % 7.2 % 7.3 % 6.8 %
Our weighted-average interest rate and weighted-average borrowing rate each remained relatively flat sequentially. Our weighted-average interest rate and weighted-average borrowing rate each increased YTD 2026-over-YTD 2025, primarily due to our Civitas Senior Notes, the majority of which carry a higher average coupon rate than our Senior Notes outstanding prior to 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 the 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.
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 and exploration of oil and gas properties are the primary use of our capital resources and totaled $2.0 billion during the nine months ended September 30, 2026. This amount differs from the costs incurred amount of $2.2 billion for the nine months ended September 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 $2.75 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 continue to execute on our strategy and bolster our balance sheet.
During the nine months ended September 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. As a result of the Tender Offer, we paid total consideration of $924 million, including the early tender premium and certain fees, and we paid $16 million of accrued interest. Refer to Note 6 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
Subsequent to the Tender Offer, 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. On September 4, 2026, we used cash flows from operations to redeem all $417 million aggregate principal amount outstanding of our 2027 Senior Notes, at par. After these redemptions, we have no Senior Notes maturities until mid-2028. Refer to Note 6 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
During the nine months ended September 30, 2026, and 2025, we repurchased and subsequently retired 4,946,833 and 444,705 shares, respectively, of our common stock at a cost of $165 million and $12 million, respectively, excluding excise taxes, commissions, and fees. As of September 30, 2026, $323 million was available under the Stock Repurchase Program for repurchases of our outstanding common stock through December 31, 2027.
During the nine months ended September 30, 2026, and 2025, we paid $187 million and $69 million, respectively, in dividends to our stockholders. In the first quarter of 2026, we began declaring and paying dividends within the same quarter, rather than paying in the quarter after declaration. As a result of this timing change, cash dividend payments during 2026 will include five payments: 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 the indentures governing our Senior Notes, and other factors that could arise. The payment and amount of future dividends remain at the discretion of our Board of Directors.
Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2026, and 2025
The following tables present changes in cash flows between the nine months ended September 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 Nine Months Ended September 30, Amount Change Between Periods
2026 2025
(in millions)
Net cash provided by operating activities $ 2,865 $ 1,559 $ 1,306
Net cash provided by operating activities increased for the nine months ended September 30, 2026, compared with the same period in 2025, primarily as a result of an increase of $2.4 billion in cash received from oil, gas, and NGL production revenue net of transportation costs and production taxes. This increase was partially offset by increases in cash paid of $406 million for settled derivative trades, $390 million for LOE, $166 million for interest, and $165 million for certain G&A expenses. 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 Nine Months Ended September 30, Amount Change Between Periods
2026 2025
(in millions)
Net cash used in investing activities $ (1,231) $ (1,244) $ 13
Net cash used in investing activities decreased for the nine months ended September 30, 2026, compared with the same period in 2025, primarily as a result of net cash proceeds of $888 million received from the South Texas Divestiture, partially offset by a $798 million increase in capital expenditures and $49 million of cash paid in connection with the Merger, net of cash acquired.
Financing activities
For the Nine Months Ended September 30, Amount Change Between Periods
2026 2025
(in millions)
Net cash used in financing activities $ (1,560) $ (153) $ (1,407)
Net cash used in financing activities of $1.6 billion for the nine months ended September 30, 2026, primarily reflects $1.2 billion used to redeem our 2026 Civitas Senior Notes, 2026 Senior Notes, and 2027 Senior Notes, $924 million, including the early tender premium and certain fees but excluding accrued interest, used to repurchase a portion of our 2028 Civitas Senior Notes through the Tender Offer, $187 million of dividends paid to our stockholders and $166 million of cash paid, including commissions and fees, to repurchase and subsequently retire 4.9 million shares of our common stock under the Stock Repurchase Program. These uses were partially offset by net proceeds of $984 million from the issuance of our 2034 Senior Notes.
Net cash used in financing activities for the nine months ended September 30, 2025, primarily related to net repayments of $69 million under our revolving credit facility and $69 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 September 30, 2026, our outstanding principal amount of fixed-rate debt totaled $6.5 billion, and we had no floating-rate debt outstanding. As of September 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.
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 nine months ended September 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 $510 million, $35 million, and $34 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the nine months ended September 30, 2026, would have offset the declines in oil, gas, and NGL production revenue by approximately $277 million.
We enter into commodity derivative contracts 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 September 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 $282 million, $89 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 nine months ended September 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 our 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 (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 Nine Months Ended
September 30,
2026 		September 30,
2025 		September 30,
2026 		September 30,
2025
(in millions)
Net income (GAAP) $ 93 $ 155 $ 829 $ 539
Interest expense 116 43 340 130
Income tax expense 30 49 273 150
Depletion, depreciation, and amortization 590 325 1,614 888
Exploration (1)
20 10 62 34
Stock-based compensation expense (2)
13 8 30 21
Net derivative (gain) loss 684 (45) 1,109 (107)
Net derivative settlement gain (loss) (207) 39 (457) 86
(Gain) loss on divestiture activity 2 - (260) -
Transaction and integration costs (3)
5 - 177 -
Other, net (5) 4 - 5
Adjusted EBITDAX (non-GAAP) 1,341 588 3,717 1,747
Interest expense (116) (43) (340) (130)
Income tax expense (30) (49) (273) (150)
Exploration (1)
(20) (10) (62) (34)
Amortization of deferred financing costs and debt premiums, net (6) 3 (16) 8
Transaction and integration costs (3)
(5) - (157) -
Deferred income tax expense (benefit) (7) 76 224 145
Other, net 26 (7) (18) (12)
Net change in working capital (61) (53) (210) (15)
Net cash provided by operating activities (GAAP) $ 1,122 $ 505 $ 2,865 $ 1,559
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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 nine months ended September 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 nine months ended September 30, 2026, these costs consisted of $4 million and $159 million, respectively, of one-time integration costs (including less than $1 million and $20 million, respectively, of stock-based compensation), which were included in G&A expense in the accompanying statements of operations, and $1 million and $18 million, respectively, of one-time transaction costs included in other operating expense in the accompanying statements of operations.
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