SM Energy Co
For the period ended Mar 31, 2026. Filed May 7, 2026.
View on SEC.govAbout this filing
A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Mar 31, 2026 · Filed May 7, 2026
SM$29.92+1.0%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2025-09-30; filed 2025-11-03.
0000893538-25-000138
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2026-03-31; filed 2026-05-07.
0000893538-26-000061
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 139 previous paragraphs and 158 current paragraphs.
52 unchanged; 55 reworded; 49 added; 31 removed; 1 previous and 2 current paragraphs rearranged.
Tables are not compared: 21 previous and 21 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (49)
Current report
On November 2, 2025, we entered into the Merger Agreement with Civitas. On January 27, 2026, our stockholders voted in favor of both proposals necessary to complete the Civitas Merger, which included approval of (i) the issuance of shares of SM Energy common stock to Civitas stockholders as contemplated by the Merger Agreement, and (ii) an amendment of our Restated Certificate of Incorporation to increase the number of authorized shares of our common stock from 200 million shares to 400 million shares.
Current report
On January 30, 2026, we completed the Civitas Merger in accordance with the terms of the Merger Agreement. Civitas was an independent exploration and production company focused on the acquisition, development, and production of crude oil and associated liquids-rich natural gas in the DJ Basin in Colorado and the Permian Basin in Texas and New Mexico. We believe that the Merger 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.
Current report
Under the terms of the Merger Agreement, subject to certain exceptions, each share of Civitas common stock was converted into the right to receive 1.45 shares of SM Energy common stock, with cash paid in lieu of fractional shares. On January 30, 2026, we issued 124 million shares to holders of Civitas common stock, representing 52 percent of the outstanding shares of SM Energy’s common stock upon the closing of the Merger. Based on the closing price of SM Energy common stock on January 30, 2026, the total stock consideration was valued at$2.4 billion.
Current report
South Texas Divestiture
Current report
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.
Current report
Debt Optimization
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
•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.
Current report
•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.
Current report
•We announced our South Texas Divestiture, which subsequently closed on April 30, 2026.
Current report
•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.
Current report
Refer to Note 2 - Mergers, Acquisitions, and Divestituresand Note 6 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
(1) Subsequent to March 31, 2026, we divested 10 gross (10 net) drilled but not completed wells as part of the South Texas Divestiture.
Current report
(2) We acquired these drilled but not completed wells as part of the Civitas Merger on January 30, 2026.
Current report
(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.
Current report
(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.
Current report
(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.
Current report
The Civitas Merger, which closed on January 30, 2026, is expected to materially affect our future operating and financial results. The addition of 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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
Approximately $118 million of general and administrative expense during the three months ended March 31, 2026, is considered one-time Civitas Merger integration cost.
Current report
Net derivative (gain) loss
Current report
Income tax (expense) benefit
Current report
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 Debtin Part I, Item 1 of this report for additional discussion.
Showing the first 40 of 49 passages. Open the source sections for the rest.
Removed paragraphs (31)
Previous report
On November 2, 2025, we entered into the Merger Agreement with Civitas and a subsidiary of SM Energy, pursuant to which, among other things, we have agreed to acquire Civitas through the Merger. Under the terms of the Merger Agreement, each eligible share of Civitas common stock will be converted into the right to receive 1.45 shares of our common stock.
Previous report
Civitas is an independent exploration and production company focused on the acquisition, development, and production of crude oil and associated liquids-rich natural gas primarily in the Denver-Julesberg Basin in Colorado and the Permian Basin in Texas and New Mexico. We expect the Merger to generate value-enhancing scale, unlock meaningful synergies, and deliver accretive substance, ultimately creating superior long-term value for our stockholders. Under the terms of the Merger, Civitas shareholders will receive 1.45 shares of our common stock in exchange for each common share of Civitas they own at closing.
Previous report
The Merger has been unanimously approved by the boards of directors of both companies. The Merger is subject to customary closing conditions, including the approval of SM Energy and Civitas shareholders and receipt of required regulatory approvals. The transaction is expected to close in the first quarter of 2026.
Previous report
The ongoing U.S. federal government shutdown has not had a material impact on our operations or financial condition to date; however, if it continues, it could affect our financial condition or results of operations in the fourth quarter of 2025 and beyond. Potential impacts may include delays in regulatory processes and approvals, disruptions to government-related activities, or broader economic effects.
Previous report
During the third quarter of 2025, we resumed activity under our Stock Repurchase Program by repurchasing and subsequently retiring approximately 0.4 million shares of our outstanding common stock at a cost of $12.1 million, excluding excise taxes, commissions, and fees. Additionally, we continued to execute on our goal of sustainably returning capital to our stockholders through our fixed quarterly dividend by paying a net cash dividend of $0.20 per share, totaling $23.0 million. In September 2025, we declared a fixed cash dividend of $0.20 per share to be paid on November 3, 2025.
Previous report
Financial and Operational Results. Average net daily equivalent production for the three months ended September 30, 2025, increased two percent sequentially to 213.8 MBOE. The overall increase consisted of an increase of 12 percent from our South Texas assets, mostly offset by decreases of five percent and two percent from our Uinta Basin and Midland Basin assets, respectively.
Previous report
Oil, gas, and NGL realized price, before the effect of net derivative settlements (“realized price” or “realized prices”), remained flat sequentially. The second and third quarters of 2025 were impacted by weak Waha pricing, which we expect will continue to impact our realized price into 2026, when additional pipeline capacity is expected to be placed into service. A portion of the negative impact was mitigated by our commodity derivative contracts in effect during the second and third quarters of 2025, and we have additional commodity derivative contracts in place for future periods. Oil, gas, and NGL production revenue increased three percent sequentially and was $811.0 million for the three months ended September 30, 2025, compared with $785.1 million for the three months ended June 30, 2025. Oil, gas, and NGL production expense increased two percent sequentially to $229.0 million for the three months ended September 30, 2025, compared with $224.0 million for the three months ended June 30, 2025.
Previous report
We recorded net derivative gains of $45.5 million and $78.3 million for the three months ended September 30, 2025, and June 30, 2025, respectively. Included within these amounts are net derivative settlement gains of $38.9 million and $39.7 million for the three months ended September 30, 2025, and June 30, 2025, respectively.
Previous report
In our Midland Basin program, we operated two drilling rigs and one completion crew during the majority of the third quarter of 2025, and our operations focused on development optimization of our RockStar assets and delineation and development of our Sweetie Peck assets. Average net daily equivalent production decreased sequentially by two percent to 82.0 MBOE. Costs incurred during the three months ended September 30, 2025, totaled $128.5 million, or 40 percent of our total costs incurred for the period. We anticipate operating an average of two drilling rigs and a spot completion crew for the majority of the remainder of 2025, focused on developing formations within our RockStar and Sweetie Peck assets.
Previous report
(1) As of December 31, 2024, the drilled but not completed well count included nine gross (nine net) wells that were not included in our five-year development plan as of December 31, 2024, eight of which were in the Eagle Ford shale.
Previous report
(2) Completions activity in our Uinta Basin program is ongoing, but no official well completions occurred during the three months ended September 30, 2025, due to pad timing.
Previous report
(3) Adjustment primarily relates to the acquisition of additional working interest in existing drilled but not completed wells.
Previous report
(1)The Uinta Basin assets were acquired on October 1, 2024.
Previous report
Average net daily equivalent production for the three months ended September 30, 2025, increased slightly sequentially as a 12 percent increase from our South Texas assets was mostly offset by decreases of five percent and two percent from our Uinta Basin assets and Midland Basin assets, respectively. Average net daily equivalent production increased 31 percent YTD 2025-over-YTD 2024 primarily driven by the addition of 44.0 MBOE per day of production from our Uinta Basin assets.
Previous report
Our total realized price remained flat sequentially. The second and third quarters of 2025 were impacted by weak Waha pricing, which we expect will continue to impact our realized price into 2026, when additional pipeline capacity is expected to be placed into service. A portion of the negative impact was mitigated by our commodity derivative contracts in effect during the second and third quarters of 2025, and we have additional commodity derivative contracts in place for future periods. We recognized net gains on the settlement of our commodity derivative contracts of $1.98 per BOE and $2.09 per BOE during the three months ended September 30, 2025, and June 30, 2025, respectively. Our total realized price increased $0.73 YTD 2025-over-YTD 2024 primarily as a result of a shift in our production mix towards more oil production, which was offset by a decrease in the benchmark oil price. We recognized net gains on the settlement of our commodity derivative contracts of $1.53 per BOE and $1.07 per BOE during the nine months ended September 30, 2025, and September 30, 2024, respectively.
Previous report
Transportation costs per BOE decreased nine percent sequentially, primarily as a result of a five percent decrease in average net daily equivalent production from our Uinta Basin assets, which have higher transportation costs per BOE. Transportation costs per BOE increased 92 percent YTD 2025-over-YTD 2024 primarily as a result of the addition of oil production from our Uinta Basin assets. In general, we expect total transportation costs to fluctuate relative to changes in gas and NGL production from our South Texas assets and oil production from our Uinta Basin assets, where we incur a majority of our transportation costs. Additionally, transportation costs related to our Uinta Basin assets can vary depending on the terms of the applicable sales contracts and the transportation method used. For the full-year 2025, we expect transportation costs per BOE to increase compared with 2024, as a result of the addition of our Uinta Basin assets.
Previous report
General and administrative (“G&A”) expense on a per BOE basis decreased 10 percent sequentially driven by decreased G&A expense on an absolute basis and increased total net equivalent production. G&A expense on a per BOE basis decreased four percent YTD 2025-over-YTD 2024 as increased total net equivalent production outpaced increased G&A expense on an absolute basis. For the full-year 2025, we expect G&A expense on an absolute basis to increase compared with 2024, primarily as a result of an increase in employee headcount attributable to the Uinta Basin Acquisition. We expect G&A expense per BOE to remain relatively flat for the full-year 2025 compared with 2024, as expected increases in G&A expense on an absolute basis are expected to be mostly offset by increases in production.
Previous report
Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2025, and June 30, 2025, and Between the Nine Months Ended September 30, 2025, and 2024
Previous report
Average net daily equivalent production increased slightly, and total realized price remained relatively flat, resulting in a three percent increase in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense increased slightly as increases in LOE and production tax expense were partially offset by a decrease in transportation expense.
Previous report
(1)Amounts reflect Uinta Basin activity for the nine months ended September 30, 2025. There was no comparable activity for the nine months ended September 30, 2024, as the Uinta Basin assets were acquired on October 1, 2024.
Previous report
Average net daily equivalent production increased 31 percent and oil, gas, and NGL production revenue increased 33 percent, primarily driven by the addition of 44.0 MBOE per day of production from our Uinta Basin assets. Oil, gas, and NGL production expense increased 61 percent driven by increases in transportation expense and LOE associated with the addition of our Uinta Basin assets.
Previous report
DD&A expense increased 11 percent sequentially and 62 percent YTD 2025-over-YTD 2024. The sequential quarterly increase was primarily driven by increases in DD&A rates across all of our assets. The YTD 2025-over-YTD 2024 increase was a result of increased average net daily equivalent production, including the addition of production from our Uinta Basin assets, and increases in our DD&A rates. Our Midland Basin and Uinta Basin assets have higher DD&A rates than our South Texas assets.
Previous report
G&A expense decreased seven percent sequentially and increased 25 percent YTD 2025-over-YTD 2024. The YTD 2025-over-YTD 2024 increase was primarily due to increased headcount and one-time G&A expenses, both of which related to the Uinta Basin Acquisition.
Previous report
Net derivative gain
Previous report
Income tax expense
Previous report
The effects of changes in tax laws are recognized in the period of enactment. On July 4, 2025, the OBBBA was enacted into law and includes, among other things, tax reform provisions that amend, eliminate, and extend tax rules under the Inflation Reduction Act and Tax Cuts and Jobs Act. During the third quarter of 2025, we recorded the impacts of the OBBBA on our full-year income tax expense, which resulted in a decrease to the current portion of income tax expense. This change reflects the impacts of the reinstatement of 100 percent bonus depreciation on tangible assets; the immediate expensing of qualified R&D expenditures and the expensing of unamortized, previously capitalized, qualified R&D expenditures; and a less restrictive limitation on the business interest expense deduction. Additionally, the OBBBA allows for the deduction of intangible drilling costs from adjusted financial statement income (“AFSI”) when determining whether a company is subject to and liable for the Corporate Alternative Minimum Tax (“CAMT”). As a result, we do not expect to become subject to or liable for the CAMT for the foreseeable future, notwithstanding other factors that may impact our AFSI.
Previous report
Our weighted-average interest and weighted-average borrowing rate each remained relatively flat sequentially, and each increased YTD 2025-over-YTD 2024 as a result of the issuance of our 2029 Senior Notes and 2032 Senior Notes, which have greater outstanding aggregate principal balances and higher interest rates than our other outstanding Senior Notes, and as a result of borrowings under our revolving credit facility. We expect our weighted-average interest rate and weighted-average borrowing rate to increase slightly for the full-year 2025 compared with 2024.
Previous report
As of September 30, 2025, we reclassified $419.2 million of principal balance of our 2026 Senior Notes as current liabilities, net of unamortized deferred financing costs, on our accompanying balance sheets. As of the filing of this report, based on current commodity prices, we expect to meet this obligation using cash on hand and projected cash provided by operating activities. As of September 30, 2025, our cash and cash equivalents balance was $162.3 million, and as of the filing of this report, we had $2.0 billion of available borrowing capacity under our revolving credit facility.
Previous report
On July 4, 2025, the OBBBA was enacted into law and we recorded the impacts of the OBBBA on our full-year income tax expense during the third quarter of 2025. As a result, we expect a reduction in the amount of cash we would have been required to pay for federal income taxes during 2025. Additional changes in federal and state income tax laws and other possible future legislation, including changes in the corporate tax rate, could have a material effect on our net cash provided by operating activities, income tax expense, tax receivable, and deferred tax liabilities. Refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2025, and June 30, 2025, and Between the Nine Months Ended September 30, 2025, and 2024 for discussion of the OBBBA.
Previous report
Net cash provided by financing activities for the nine months ended September 30, 2024, primarily related to the net cash proceeds of $1.48 billion received from the issuance of the 2029 Senior Notes and 2032 Senior Notes, partially offset by $349.1 million of cash paid to redeem our 2025 Senior Notes, $84.0 million of cash paid, including commissions and fees, to repurchase and subsequently retire 1.8 million shares of our common stock under the Stock Repurchase Program and $62.1 million of dividends paid to our stockholders.
Previous report
(2) For the three and nine months ended September 30, 2024, amounts exclude certain capital expenditures primarily related to one well deemed non-commercial.
Reworded paragraphs (55)
Previous wording
The following discussion includes forward-looking statements. Refer to the Cautionary Information about Forward-Looking Statements section of this report for important information about these types of statements. Additionally, the following discussion includes sequential quarterly comparison to the financial information presented in our Quarterly Report on the Form 10-Q for the quarter ended June 30, 2025, filed with the Securities and Exchange Commission (“SEC”) on August 1, 2025. Throughout the following discussion, we explain changes between the three months ended September 30, 2025, and the three months ended June 30, 2025 (“sequential quarterly” or “sequentially”), and the year-to-date (“YTD”) change between the nine months ended September 30, 2025, and the nine months ended September 30, 2024 (“YTD 2025-over-YTD 2024”).
Current wording
The following discussion includes forward-looking statements. Refer to the Cautionary Information about Forward-Looking Statements section of this report for important information about these types of statements. 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”).
Previous wording
Our asset portfolio is comprised of high-quality assets in the Midland Basin of West Texas, the Maverick Basin of South Texas, and the Uinta Basin of Northeast Utah, which we believe are capable of generating strong returns in the current macroeconomic environment and provide resilience to commodity price risk and volatility. We seek to maximize returns and increase the value of our top-tier assets through disciplined capital spending, strategic acquisitions, and continued development and optimization. We believe that our high-quality assets facilitate a sustainable approach to prioritizing operational execution, maintaining a strong balance sheet, generating cash flows, returning capital to stockholders, and maintaining financial flexibility.
Current wording
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.
Previous wording
We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; building and maintaining partnerships with our stakeholders by investing in and connecting with the communities where we live and work; and transparently reporting on 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.
Current wording
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.
Previous wording
“OPEC+”); fluctuations in oil and gas demand from China and other markets; War and Geopolitical Instability; United States Federal Reserve monetary policy; global shipping channel constraints and disruptions; the potential for economic recession in the U.S.; and changes in global oil inventory in storage. These factors have driven commodity price volatility, contributed to instances of supply chain disruptions, inflation, and fluctuations in interest rates, and could have further industry-specific impacts that may require us to adjust our business plan. Future impacts of these and other events on commodity and financial markets are inherently unpredictable.
Current wording
As global commodities, the prices of oil, gas, and NGLs, as well as broader financial markets, remain subject to heightened uncertainty and volatility. Market conditions are influenced by factors including real or perceived geopolitical risks; War and Geopolitical Instability; 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.
Previous wording
Historically, tariffs have led to increased costs for products exchanged in international trade, and have heightened global political tensions. Recent U.S. government policies, including new and higher tariffs on imported goods, have increased economic uncertainty. These tariffs, along with retaliatory tariffs from other countries, could lead to reduced trade resulting from increased costs for imported goods and decreased demand for U.S. exports, as well as reduced investment and technological exchange between major economies. These outcomes could negatively impact global economic conditions, financial market stability, and commodity prices. Volatility in political, trade, regulatory, and economic conditions could have a material adverse effect on our financial condition or results of operations. We are unable to reasonably estimate the period of time that these market conditions will exist or the extent to which they will impact our business, results of operations, and financial condition.
Current wording
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.
Previous wording
Our Midland Basin assets are comprised of approximately 107,000 net acres located in the Permian Basin in West Texas (“Midland Basin”) and provide future development and exploration opportunities within multiple oil-rich intervals, including the Spraberry, Wolfcamp, and Woodford Barnett formations.
Current wording
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.
Previous wording
Our South Texas assets are comprised of approximately 155,000 net acres located in Dimmit and Webb counties, Texas (“South Texas”). Our overlapping acreage position in South Texas covers a significant portion of the western Eagle Ford shale and Austin Chalk formations, and includes acreage across the oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction.
Current wording
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.
Previous wording
Our Uinta Basin assets are comprised of approximately 62,000 net acres located in Duchesne and Uintah counties, Utah (“Uinta Basin”) and provide future development and exploration opportunities within multiple oil-rich intervals in the Lower Green River and Wasatch formations, and includes acreage with waxy crude and gas composition amenable to processing for NGL extraction.
Current wording
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.
Previous wording
Third Quarter 2025 Overview and Outlook for the Remainder of 2025
Current wording
First Quarter 2026 Overview and Outlook for the Remainder of 2026
Previous wording
Our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to domestic energy security and prosperity, and having a positive impact in the communities where we live and work. Our long-term vision and strategy is to sustainably grow value for all of our stakeholders as a premier operator of top-tier assets by maintaining and optimizing our high-quality asset portfolio, generating cash flows, and maintaining a strong balance sheet. Our team executes this strategy by prioritizing safety, technological innovation, and stewardship of natural resources, all of which are integral to our corporate culture. During the first half of 2025, we focused on the successful integration of our Uinta Basin assets. We have shifted our focus for the second half of 2025 to optimizing operations and development to deliver sustained value from this core asset. Our near-term goals include focusing on operational execution; generating cash flows that enable us to continue returning value to stockholders through fixed dividend payments, debt repayments, and our Stock Repurchase Program; and expanding our portfolio of top-tier economic drilling inventory through acquisition and exploration.
Current wording
During the first quarter of 2026:
Previous wording
•Net income of $155.1 million, or $1.35 per diluted share, compared with net income of $201.7 million, or $1.76 per diluted share, for the three months ended June 30, 2025.
Current wording
•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.
Previous wording
•Net cash provided by operating activities of $505.0 million, compared with $571.1 million for the three months ended June 30, 2025. The decrease in net cash provided by operating activities was primarily a result of timing of interest payments on our Senior Notes.
Current wording
•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.
Previous wording
•Adjusted EBITDAX, a non-GAAP financial measure, of $588.2 million, compared with $569.6 million for the three months ended June 30, 2025. 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.
Current wording
•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.
Previous wording
Refer to Overview of Selected Production and Financial Information, Including Trendsand Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2025, and June 30, 2025, and Between the Nine Months Ended September 30, 2025, and 2024 below for additional discussion.
Current wording
Refer to Overview of Selected Production and Financial Information, Including Trendsand 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.
Previous wording
Operational Activities. Our capital program for 2025, excluding acquisitions, is expected to be approximately $1.375 billion and includes certain non-operated capital projects. Our capital program remains focused on applying our strength in geosciences and development optimization to highly economic oil 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 2025 capital program.
Current wording
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.
Previous wording
During the three and nine months ended September 30, 2025, costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $323.7 million and $1.17 billion, respectively. Total costs incurred includes activity in our core areas of operations and corporate charges incurred in exploration activities and costs related to exploration efforts outside of our core areas of operation.
Current wording
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.
Previous wording
In our South Texas program, we operated one drilling rig and one spot completion crew during the third quarter of 2025, and our operations focused primarily on the development and further delineation of the Austin Chalk formation. Average net daily equivalent production increased sequentially by 12 percent to 86.4 MBOE. Costs incurred during the three months ended September 30, 2025, totaled $76.4 million, or 24 percent of our total costs incurred for the period. We anticipate operating one or two drilling rigs and one spot completion crew for a majority of the remainder of 2025, focused primarily on developing the Austin Chalk formation.
Current wording
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.
Previous wording
In our Uinta Basin program, we operated three drilling rigs and one completion crew during the third quarter of 2025, and our operations focused on delineation and development. Average net daily equivalent production decreased sequentially by five percent to 45.5 MBOE. Costs incurred during the three months ended September 30, 2025, totaled $107.7 million, or 33 percent of our total costs incurred for the period. We anticipate operating three drilling rigs and one completion crew during the remainder of 2025, focused primarily on delineating and developing the Lower Green River and Wasatch formations.
Current wording
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.
Previous wording
The table below provides a quarterly summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs for the three and nine months ended September 30, 2025:
Current wording
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:
Previous wording
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:
Current wording
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.
Previous wording
Refer to Overview of Selected Production and Financial Information, Including Trendsand Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2025, and June 30, 2025, and Between the Nine Months Ended September 30, 2025, and 2024 below for discussion of production.
Current wording
Refer to Overview of Selected Production and Financial Information, Including Trendsand 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.
Previous wording
Given the uncertainty surrounding 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.
Current wording
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.
Previous wording
(2) Net derivative settlements for the three months ended September 30, 2025, and for the nine months ended September 30, 2025, and 2024, are included within the net derivative gain line item in the accompanying statements of operations.
Current wording
(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.
Previous wording
Lease operating expense (“LOE”) per BOE increased three percent sequentially as a result of timing of workover projects. LOE per BOE increased 15 percent YTD 2025-over-YTD 2024 as a result of a shift in our production mix towards more oil production and increases in certain operating costs. For the full-year 2025, we expect LOE per BOE to increase, compared with 2024, due to higher oil production and expected increases in certain operating costs associated with our Midland Basin assets. We anticipate volatility in LOE per BOE as a result of changes in production mix, timing of workover projects, changes in service provider costs, and industry activity, all of which affect total LOE.
Current wording
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.
Previous wording
Production tax expense per BOE increased six percent sequentially primarily as a result of an increase in oil realized price and changes in production mix across our assets. Production tax expense per BOE decreased six percent YTD 2025-over-YTD 2024, primarily as a result of a decrease in oil realized price per BOE. Our overall production tax rate was 4.1 percent and 3.9 percent for the three months ended September 30, 2025, and June 30, 2025, respectively, and was 4.1 percent and 4.4 percent for the nine months ended September 30, 2025, and 2024, respectively. We expect that our Uinta Basin assets will incur a lower production tax rate compared with our Midland Basin and South Texas assets. We generally expect production tax expense to correlate with oil, gas, and NGL production revenue on a per BOE and absolute basis. Product mix, the location of production, and incentives to encourage oil and gas development can also impact the amount of production tax expense that we recognize.
Current wording
Production tax expense 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.
Previous wording
Ad valorem tax expense per BOE decreased six percent sequentially and 35 percent YTD 2025-over-YTD 2024, 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 as a result of varying tax policies across the different counties in which we operate.
Current wording
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.
Previous wording
Depletion, depreciation, and amortization (“DD&A”) expense per BOE increased seven percent sequentially, primarily driven by expected increases in DD&A rates as our capital allocation shifts with the inclusion of our Uinta Basin assets. DD&A expense per BOE increased 24 percent YTD 2025-over-YTD 2024 as a result of the addition of our Uinta Basin assets and a shift in our production mix. Our Midland Basin and Uinta Basin assets have higher DD&A rates than our South Texas 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 2025, we expect DD&A expense per BOE and on an absolute basis to increase, compared with 2024, primarily as a result of expected increased production resulting from the addition of our Uinta Basin assets and a shift in our production mix.
Current wording
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.
Previous wording
Refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2025, and June 30, 2025, and Between the Nine Months Ended September 30, 2025, and 2024 below for additional discussion of operating expenses.
Current wording
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.
Previous wording
YTD 2025-over-YTD 2024 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, 2025, and 2024:
Current wording
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:
Previous wording
Exploration expense decreased 25 percent sequentially and 19 percent YTD 2025-over-YTD 2024 as a result of decreases in geological, geophysical, and other expenses. Exploration expense fluctuates based on actual geological and geophysical studies we perform within an exploratory area, exploratory dry hole expense incurred, and changes in the amount of allocated overhead.
Current wording
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.
Previous wording
Net derivative gain is a result of changes in fair values associated with fluctuations in the forward price curves for the commodities underlying our outstanding derivative contracts and the monthly cash settlements of our derivative positions during the period. We expect increases in benchmark commodity prices to result in net derivative losses and decreases in benchmark commodity prices to result in net derivative gains, as measured against our derivative contract prices. Refer to Note 7 - Derivative Financial Instruments in Part I, Item 1 of this report for additional discussion.
Current wording
Net derivative (gain) loss is a result of changes in fair values associated with fluctuations in the forward price curves for the commodities underlying our outstanding derivative contracts and the monthly cash settlements of our derivative positions during the period. 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.
Previous wording
Interest expense remained relatively flat sequentially and increased 38 percent YTD 2025-over-YTD 2024. The YTD 2025-over-YTD 2024 increase was primarily a result of the issuance of our 2029 Senior Notes and our 2032 Senior Notes during the third quarter of 2024, and an increase in interest expense associated with borrowings under our revolving credit facility. Total interest expense can vary based on the amount of our outstanding fixed-rate debt securities, fluctuations in the amount of capitalized interest 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.
Current wording
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.
Previous wording
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 increased both sequentially and YTD 2025-over-YTD 2024, primarily as a result of the impact of newly enacted limitations on the R&D credit calculation under the OBBBA, partially offset by the impact of statutory changes related to the Texas R&D credit calculation that benefited the second quarter of 2025. The sequential quarterly increase also reflects the impact of excess tax deficiencies from stock-based compensation awards.
Current wording
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.
Previous wording
Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan while continuing to meet our financial obligations, including near-term maturities of our outstanding Senior Notes. We continue to manage the duration and level of our drilling and completion service commitments in order to maintain flexibility with regard to our activity level and capital expenditures.
Current wording
Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan while continuing to meet our 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.
Previous wording
During the nine months ended September 30, 2025, we primarily funded our capital expenditures and return of capital program with cash flows from operating activities. For the remainder of 2025, 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 2025, 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.
Current wording
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.
Previous wording
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. 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.
Current wording
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.
Previous wording
Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $3.0 billion. As of September 30, 2025, the borrowing base and aggregate revolving lender commitments under our Credit Agreement were $3.0 billion and $2.0 billion, respectively. The borrowing base is subject to regular, semi-annual redetermination, and considers the value of both our proved oil and gas properties reflected in our most recent reserve report and commodity derivative contracts, each as determined by our lender group. Subsequent to September 30, 2025, our lender group reaffirmed our borrowing base and aggregate lender commitments at existing amounts. The next borrowing base redetermination is scheduled to occur on April 1, 2026. In connection with the semi-annual borrowing base redetermination, we entered into the Third Amendment with our lenders to amend the springing maturity provision of the Credit Agreement to provide a more flexible structure based on the amount of our short-term debt outstanding and our borrowing availability. No individual bank participating in our Credit Agreement represents more than 10 percent of the lender commitments under the Credit Agreement. We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement. We were in compliance with all financial and non-financial covenants under the Credit Agreement as of September 30, 2025, and through the filing of this report.
Current wording
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.
Previous wording
Our weighted-average interest rate includes paid and accrued interest, fees on the unused portion of the aggregate revolving lender commitment amount under the Credit Agreement, letter of credit fees, and the non-cash amortization of deferred financing costs. Our weighted-average borrowing rate includes paid and accrued interest only.
Current wording
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.
Previous wording
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 nine months ended September 30, 2025, we spent $1.22 billion on capital expenditures. This amount differs from the costs incurred amount of $1.17 billion for the nine months ended September 30, 2025, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, acquisitions of oil and gas properties, and exploration overhead amounts.
Current wording
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.
Previous wording
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 2025, excluding acquisitions, is expected to be approximately $1.375 billion and includes certain non-operated capital projects.
Current wording
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.
Showing the first 40 of 55 pairs. Open the source sections for the rest.
Rearranged current paragraphs (2)
Current report — wording carried from elsewhere
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
Current report — wording carried from elsewhere
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.
Rearranged previous paragraphs (1)
Previous report — wording carried elsewhere
Global commodity and financial markets, which remain subject to heightened levels of uncertainty and volatility, affect our financial performance. Key factors contributing to market fluctuations include tariffs and trade restrictions; production output from the Organization of the Petroleum Exporting Countries (“OPEC”) plus other non-OPEC oil producing countries (collectively referred to as