SM Energy Co
For the period ended Sep 30, 2025. Filed Nov 3, 2025.
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.
Sep 30, 2025 · Filed Nov 3, 2025
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 2025-06-30; filed 2025-08-01.
0000893538-25-000113
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent 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 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 131 previous paragraphs and 139 current paragraphs.
64 unchanged; 60 reworded; 14 added; 5 removed; 2 previous and 1 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 (14)
Current report
Merger with Civitas
Current 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.
Current 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.
Current 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.
Current 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.
Current 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.
Current 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.
Current 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.
Current report
(3) Adjustment primarily relates to the acquisition of additional working interest in existing drilled but not completed wells.
Current 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
Current 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.
Current report
Net derivative gain
Current 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.
Current 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.
Removed paragraphs (5)
Previous report
During the second quarter of 2025, we completed the integration of the Uinta Basin assets into our portfolio. We also reduced our total outstanding debt by paying off the balance on our revolving credit facility and ending the quarter with a cash and cash equivalents balance of $101.9 million as of June 30, 2025. Additionally, we continued to execute on our goal of sustainably returning capital to our stockholders by paying a quarterly net cash dividend of $0.20 per share, totaling $22.9 million.
Previous report
Oil, gas, and NGL realized prices per BOE, before the effect of net derivative settlements (“realized price” or “realized prices”), decreased sequentially by 12 percent, 35 percent, and 15 percent, respectively, as a result of decreases in oil, gas and NGL benchmark prices during the second quarter of 2025. The decrease in our realized gas price was also a result of weaker Waha pricing during the second quarter of 2025. Total realized price per BOE decreased 13 percent sequentially, resulting in a six percent decrease in oil, gas, and NGL production revenue, which was $785.1 million for the three months ended June 30, 2025, compared with $839.6 million for the three months ended March 31, 2025. Oil, gas, and NGL production expense remained flat sequentially at $224.0 million for the three months ended June 30, 2025, compared with $225.1 million for the three months ended March 31, 2025, as the increase in transportation expense was offset by decreases in production tax expense and lease operating expense (“LOE”).
Previous report
Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2025, and March 31, 2025, and Between the Six Months Ended June 30, 2025, and 2024
Previous report
Average net daily equivalent production volumes increased six percent, consisting of increases of 25 percent and three percent from our Uinta Basin and Midland Basin assets, respectively. As a result of decreases in benchmark commodity prices, total realized price per BOE decreased 13 percent. The decrease in total realized price per BOE was partially offset by the increase in average net daily equivalent production volumes resulting in a six percent decrease in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense remained flat, as a result of an increase in transportation expense which was offset by decreases in production tax expense and LOE.
Previous report
Net derivative (gain) loss
Reworded paragraphs (60)
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 March 31, 2025, filed with the SEC on May 2, 2025. Throughout the following discussion, we explain changes between the three months ended June 30, 2025, and the three months ended March 31, 2025 (“sequential quarterly” or “sequentially”), and the year-to-date (“YTD”) change between the six months ended June 30, 2025, and the six months ended June 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. 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”).
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 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
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.
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 transparency in 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
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.
Previous wording
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 “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
“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.
Previous wording
Continuing volatility in political, trade, regulatory and economic conditions could impact supply and demand fundamentals, and any related declines in oil, gas, and NGL prices could lead to proved and unproved property impairments in the future. Future impairments of proved and unproved properties are difficult to predict, especially in a volatile price environment.
Current wording
Continuing volatility in political, trade, regulatory and economic conditions could impact supply and demand fundamentals, and any related declines in oil, gas, and NGL prices could lead to impairments of proved and unproved properties in the future. Future impairments of proved and unproved properties are difficult to predict, especially in a volatile price environment.
Previous wording
Our Midland Basin assets are comprised of approximately 108,000 net acres located in the Permian Basin in West Texas (“Midland Basin”). Our Midland Basin position provides future development opportunities within multiple oil-rich intervals, including the Spraberry, Wolfcamp, and Woodford Barnett formations.
Current 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.
Previous wording
Our Uinta Basin assets are comprised of approximately 64,000 net acres located in Duchesne and Uintah counties, Utah (“Uinta Basin”). Our Uinta Basin position provides 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 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.
Previous wording
Second Quarter 2025 Overview and Outlook for the Remainder of 2025
Current wording
Third Quarter 2025 Overview and Outlook for the Remainder of 2025
Previous wording
Financial and Operational Results. Average net daily equivalent production for the three months ended June 30, 2025, increased six percent sequentially to 209.1 MBOE. The overall increase consisted of increases of 25 percent and three percent from our Uinta Basin and Midland Basin assets, respectively. Average net daily equivalent production from our South Texas assets remained flat sequentially.
Current wording
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 wording
We recorded a net derivative gain of $78.3 million and a net derivative loss of $17.2 million for the three months ended June 30, 2025, and March 31, 2025, respectively. Included within these amounts are net derivative settlement gains of $39.7 million and $7.8 million for the three months ended June 30, 2025, and March 31, 2025, respectively.
Current wording
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 wording
•Net income of $201.7 million, or $1.76 per diluted share, compared with net income of $182.3 million, or $1.59 per diluted share, for the three months ended March 31, 2025.
Current 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.
Previous wording
•Net cash provided by operating activities of $571.1 million, compared with $483.0 million for the three months ended March 31, 2025. The increase 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 $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.
Previous wording
•Adjusted EBITDAX, a non-GAAP financial measure, of $569.6 million, compared with $588.9 million for the three months ended March 31, 2025. The decrease in adjusted EBITDAX was primarily a result of decreased realized prices. 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 $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.
Previous wording
Refer to Overview of Selected Production and Financial Information, Including Trendsand Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2025, and March 31, 2025, and Between the Six Months Ended June 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 September 30, 2025, and June 30, 2025, and Between the Nine Months Ended September 30, 2025, and 2024 below for additional discussion.
Previous wording
Operational Activities. Our capital program for 2025, excluding acquisitions, is expected to be approximately $1.375 billion which is an increase from our original expectation of approximately $1.3 billion. This increase is primarily to accommodate certain previously excluded 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 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.
Previous wording
During the three and six months ended June 30, 2025, costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $392.7 million and $842.4 million, respectively. Total costs incurred also includes corporate charges incurred in exploration activities and costs related to exploration efforts outside of our core areas of operation.
Current 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.
Previous wording
In our Midland Basin program, we averaged two drilling rigs and one completion crew during the second quarter of 2025, and our operations focused on development optimization of our RockStar assets, and delineation and development of our Sweetie Peck and Klondike assets. Average net daily equivalent production volumes increased sequentially by three percent to 83.6 MBOE. Costs incurred during the three months ended June 30, 2025, totaled $148.1 million, or 38 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.
Current wording
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 wording
In our South Texas program, we averaged one drilling rig and one completion crew during the second quarter of 2025, and our operations focused primarily on the development and further delineation of the Austin Chalk formation. Average net daily equivalent production volumes remained flat sequentially at 77.4 MBOE. Costs incurred during the three months ended June 30, 2025, totaled $112.4 million, or 29 percent of our total costs incurred for the period. We anticipate operating between one and two drilling rigs and a 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 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.
Previous wording
In our Uinta Basin program, we operated three drilling rigs and one completion crew during the second quarter of 2025, and our operations focused on delineation and development. Average net daily equivalent production volumes increased sequentially by 25 percent to 48.0 MBOE. Costs incurred during the three months ended June 30, 2025, totaled $120.2 million, or 31 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 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.
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 six months ended June 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 and nine months ended September 30, 2025:
Previous wording
Refer to Overview of Selected Production and Financial Information, Including Trendsand Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2025, and March 31, 2025, and Between the Six Months Ended June 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 September 30, 2025, and June 30, 2025, and Between the Nine Months Ended September 30, 2025, and 2024 below for discussion of production.
Previous wording
(2) Net derivative settlements for the three months ended June 30, 2025, and for the six months ended June 30, 2025, and 2024, are included within the net derivative (gain) loss line item in the accompanying statements of operations.
Current 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.
Previous wording
Average net daily equivalent production for the three months ended June 30, 2025, increased six percent sequentially. The overall increase consisted of increases of 25 percent and three percent from our Uinta Basin and Midland Basin assets, respectively. Average net daily equivalent production increased 34 percent YTD 2025-over-YTD 2024 primarily driven by the addition of 43.3 MBOE per day of production from our Uinta Basin assets, and as a result of strong well performance and the timing of well completions; average net daily equivalent production from our Midland Basin and South Texas assets increased seven percent and four percent respectively.
Current wording
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 wording
Our total realized price per BOE decreased $6.02 sequentially as a result of decreases in oil, gas and NGL benchmark prices. The decrease in our realized gas price was also a result of weaker Waha pricing during the second quarter of 2025. We expect lower Waha pricing to continue to impact our realized prices for gas into 2026, when additional pipeline capacity is expected to be placed into service. Our total realized price per BOE increased $0.98 YTD 2025-over-YTD 2024 as a result of a shift in our production mix towards more oil production, and an increase in gas benchmark prices, partially offset by decreases in oil and NGL benchmark prices. We recognized net gains on the settlement of our commodity derivative contracts of $2.09 per BOE and $0.44 per BOE, during the three months ended June 30, 2025, and March 31, 2025, respectively, and $1.29 per BOE and $1.08 per BOE, during the six months ended June 30, 2025, and 2024, respectively.
Current wording
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 wording
LOE per BOE decreased 10 percent sequentially as a result of decreases in certain operating costs including workover expense, and increased average net daily equivalent production. LOE per BOE increased 13 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 total production, 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 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.
Previous wording
Transportation costs per BOE increased five percent sequentially, primarily due to a shift in production mix, with a higher contribution from our Uinta Basin assets, which have higher transportation costs per BOE. Transportation costs per BOE increased 102 percent YTD 2025-over-YTD 2024 primarily as a result of the addition of oil production from our Uinta Basin assets and increased production from our South Texas 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. 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.
Current wording
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 wording
Production tax expense per BOE decreased 23 percent sequentially primarily as a result of a decrease in total realized price per BOE. Production tax expense per BOE decreased four 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 3.9 percent and 4.4 percent for the three months ended June 30, 2025, and March 31, 2025, respectively, and was 4.1 percent and 4.4 percent for the six months ended June 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 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.
Previous wording
Ad valorem tax expense per BOE decreased two percent sequentially and 37 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 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.
Previous wording
Depletion, depreciation, and amortization (“DD&A”) expense per BOE remained relatively flat sequentially and increased 22 percent YTD 2025-over-YTD 2024. The YTD 2025-over-YTD 2024 increase was 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
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.
Previous wording
General and administrative (“G&A”) expense on a per BOE basis remained flat sequentially and YTD 2025-over-YTD 2024. 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.
Current wording
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 wording
Refer to Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2025, and March 31, 2025, and Between the Six Months Ended June 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 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.
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 six months ended June 30, 2025, and 2024:
Current 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:
Previous wording
(1)Amounts reflect Uinta Basin activity for the six months ended June 30, 2025. There was no comparable activity for the six months ended June 30, 2024, as the Uinta Basin assets were acquired on October 1, 2024.
Current wording
(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 wording
Average net daily equivalent production volumes increased 34 percent, primarily driven by the addition of 43.3 MBOE per day of production from our Uinta Basin assets. Average net daily equivalent production from our Midland Basin and South Texas assets increased seven percent and four percent, respectively. Oil, gas, and NGL production revenue increased 36 percent, primarily driven by the addition of our Uinta Basin assets, and oil, gas, and NGL production expense increased 64 percent, driven by increases in transportation expense, LOE, and production tax expense.
Current wording
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 wording
DD&A expense increased nine percent sequentially, primarily driven by an increase in average net daily equivalent production. DD&A expense increased 63 percent YTD 2025-over-YTD 2024 as 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.
Current wording
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 wording
Exploration expense increased 31 percent sequentially, primarily due to an increase in geological, geophysical, and other expenses. Exploration expense decreased 24 percent YTD 2025-over-YTD 2024 primarily as a result of a decrease in geological, geophysical, and other expenses, partially offset by an increase in exploration overhead expense. 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 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.
Previous wording
G&A expense increased seven percent sequentially, primarily due to increased compensation expense. G&A expense increased 33 percent YTD 2025-over-YTD 2024 primarily due to increased headcount and one-time G&A expenses, both of which related to the Uinta Basin Acquisition.
Current wording
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 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. 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 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.
Previous wording
Interest expense decreased four percent sequentially due to a decrease in our daily weighted-average revolving credit facility balance. Interest expense increased 99 percent YTD 2025-over-YTD 2024 primarily as a result of the issuance of our 6.75% Senior Notes due 2029 (“2029 Senior Notes”) and our 7.0% Senior Notes due 2032 (“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 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.
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 benefited both sequentially and YTD 2025-over-YTD 2024 from enacted statutory changes related to Texas research and development (“R&D”) credits during the second quarter of 2025, and we expect to continue to benefit from these changes in future periods.
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 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.
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Current report — wording carried from 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
Rearranged previous paragraphs (2)
Previous report — wording carried elsewhere
The effects of changes in tax laws are recognized in the period of enactment, therefore, we expect to record the impacts of the OBBBA on full-year income tax expense during the third quarter of 2025.
Previous report — wording carried elsewhere
Net cash used in financing activities for the six months ended June 30, 2025, primarily related to net repayments of $68.5 million under our revolving credit facility and $45.8 million of dividends paid to our stockholders.