SM Energy Co
For the period ended Jun 30, 2025. Filed Aug 1, 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.
Jun 30, 2025 · Filed Aug 1, 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 2025-03-31; filed 2025-05-02.
0000893538-25-000040
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent 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 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 131 current paragraphs.
61 unchanged; 62 reworded; 8 added; 7 removed; 1 previous and 0 current paragraphs rearranged.
Tables are not compared: 20 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 (8)
Current report
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 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”).
Current 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
Current report
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 report
Net derivative (gain) loss
Current report
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. We are currently evaluating the potential impacts of the OBBBA on our financial statements, tax position, liquidity, and financial condition. While this evaluation is ongoing, we expect to benefit from certain provisions including: 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.
Current report
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.
Current report
The following table summarizes our daily weighted-average revolving credit facility balance during the periods presented:
Removed paragraphs (7)
Previous report
Financial and Operational Results. Average net daily equivalent production for the three months ended March 31, 2025, decreased five percent sequentially to 197.3 MBOE. The overall decrease consisted of decreases of 13 percent and two percent from our South Texas and Midland Basin assets, respectively, partially offset by an increase of six percent from our Uinta Basin assets. The decreases in average net daily equivalent production from our South Texas and Midland Basin assets were anticipated during the first quarter of 2025 as a result of no completion crews operating in South Texas during the fourth quarter of 2024, and the planned timing of well completions in the Midland Basin. These anticipated changes also reflect a shift in capital allocation to our Uinta Basin assets.
Previous report
Oil, gas, and NGL production revenue remained flat at $839.6 million for the three months ended March 31, 2025, compared with $835.9 million for the three months ended December 31, 2024. Oil, gas, and NGL production expense increased five percent to $225.1 million for the three months ended March 31, 2025, compared with $214.6 million for the three months ended December 31, 2024, as a result of increases in ad valorem tax expense and lease operating expense (“LOE”), partially offset by a decrease in transportation costs.
Previous report
Realized price per BOE, before the effect of net derivative settlements (“realized price” or “realized prices”), increased eight percent sequentially, as a result of increases in oil, gas and NGL benchmark prices during the first quarter of 2025. The increase in realized price per BOE was offset by a five percent decrease in average net daily equivalent production, resulting in oil, gas, and NGL production revenue remaining flat sequentially.
Previous report
G&A expense decreased six percent sequentially, primarily due to a decrease in one-time expenses associated with the Uinta Basin Acquisition. G&A expense increased 30 percent YTD 2025-over-YTD 2024 primarily as a result of increased compensation and G&A expenses associated with the Uinta Basin Acquisition.
Previous report
Net derivative loss
Previous report
Based on current projections, we estimate that after utilization of a portion of research and development credits, between $85.0 million and $95.0 million of full-year 2025 income tax expense will be current.
Previous report
Changes in federal income tax laws could increase our corporate income tax rate and eliminate or reduce current tax deductions. Other possible future legislation could reduce our net cash provided by operating activities resulting in a reduction of available funding.
Reworded paragraphs (62)
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. Throughout the following discussion, we explain changes between the three months ended March 31, 2025, and the three months ended December 31, 2024 (“sequential quarterly” or “sequentially”), and the year-to-date (“YTD”) change between the three months ended March 31, 2025, and the three months ended March 31, 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 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”).
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. Our near-term goals include focusing on operational execution and successfully integrating the Uinta Basin assets; 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 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
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 of our existing assets. 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
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.
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 eligible employees under our long-term incentive plan, and compensation for all employees under our short-term incentive plan is calculated based on, in part, certain Company-wide, performance-based 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 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.
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; the decision of the Organization of the Petroleum Exporting Countries (“OPEC”) plus other non-OPEC oil producing countries (collectively referred to as “OPEC+”) to increase oil output in the second quarter of 2025; fluctuations in oil and gas demand from China and other markets; War and Geopolitical Instability; United States Federal Reserve monetary policy; 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
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.
Previous wording
Our Midland Basin assets are comprised of approximately 110,000 net acres located in the Permian Basin in West Texas (“Midland Basin”). Our Midland Basin position provides substantial 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 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.
Previous wording
Our Uinta Basin assets, which we acquired during the fourth quarter of 2024, are comprised of approximately 63,600 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 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.
Previous wording
First Quarter 2025 Overview and Outlook for the Remainder of 2025
Current wording
Second Quarter 2025 Overview and Outlook for the Remainder of 2025
Previous wording
During the first quarter of 2025, we remained focused on integrating the Uinta Basin assets into our portfolio and 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.
Current wording
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 wording
We recorded net derivative losses of $17.2 million and $20.3 million for the three months ended March 31, 2025, and December 31, 2024, respectively. Included within these amounts are net derivative settlement gains of $7.8 million and $22.4 million for the three months ended March 31, 2025, and December 31, 2024, respectively.
Current 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.
Previous wording
•Net income of $182.3 million, or $1.59 per diluted share, compared with net income of $188.3 million, or $1.64 per diluted share, for the three months ended December 31, 2024.
Current 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.
Previous wording
•Net cash provided by operating activities of $483.0 million, compared with $577.9 million for the three months ended December 31, 2024.
Current 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.
Previous wording
•Adjusted EBITDAX, a non-GAAP financial measure, of $588.9 million, compared with $610.8 million for the three months ended December 31, 2024. 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 $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.
Previous 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, 2025, and December 31, 2024, and Between the Three Months Ended March 31, 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 June 30, 2025, and March 31, 2025, and Between the Six Months Ended June 30, 2025, and 2024 below for additional discussion.
Previous wording
Operational Activities. Our capital program for 2025, excluding acquisitions, is expected to be approximately $1.3 billion. 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 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.
Previous wording
Costs Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $449.7 million for the three months ended March 31, 2025, and were primarily incurred in our Midland Basin, South Texas, and Uinta Basin programs as discussed in Operational Activities above.
Current 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.
Previous wording
In our Midland Basin program, we averaged four drilling rigs and one completion crew during the first 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 decreased sequentially by two percent to 81.5 MBOE. Costs incurred during the three months ended March 31, 2025, totaled $182.8 million, or 41 percent of our total costs incurred for the period. We anticipate operating an average of two drilling rigs and one completion crew for the remainder of 2025, focused on developing formations within our RockStar, Sweetie Peck, and Klondike assets.
Current 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.
Previous wording
In our South Texas program, we averaged two drilling rigs and one completion crew during the first 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 decreased sequentially by 13 percent to 77.4 MBOE. Costs incurred during the three months ended March 31, 2025, totaled $111.0 million, or 25 percent of our total costs incurred for the period. We anticipate operating between one and two drilling rigs and one completion crew for the remainder of 2025, focused primarily on developing the Austin Chalk formation.
Current 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.
Previous wording
In our Uinta Basin program, we operated three drilling rigs and one completion crew during the first quarter of 2025, and our operations focused on delineation and development. Average net daily equivalent production volumes increased sequentially by six percent to 38.4 MBOE. Costs incurred during the three months ended March 31, 2025, totaled $144.9 million, or 32 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 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.
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 months ended March 31, 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 six months ended June 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 March 31, 2025, and December 31, 2024, and Between the Three Months Ended March 31, 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 June 30, 2025, and March 31, 2025, and Between the Six Months Ended June 30, 2025, and 2024 below for discussion of production.
Previous wording
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. Given the uncertainty surrounding global financial markets, including the imposition of tariffs and trade restrictions, production output from OPEC+, global shipping channel constraints and disruptions, fluctuations in oil and gas demand from China and other markets, War and Geopolitical Instability, the potential for economic recession in the U.S., changes in global oil inventory in storage, and the potential impacts of these issues on global commodity supply and demand, we expect benchmark prices for oil, gas, and NGLs to remain volatile for the foreseeable future, and we cannot reasonably predict the timing or likelihood of any future impacts that may result, which could include inflation, supply chain disruptions, fluctuations in interest rates, and industry-specific impacts. Our realized prices at local sales points may also be affected by infrastructure capacity or outages in the areas of our operations and beyond.
Current 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.
Previous wording
(2) Net derivative settlements for the three months ended March 31, 2025, and 2024, are included within the net derivative loss line item in the accompanying statements of operations.
Current 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.
Previous wording
Average net daily equivalent production for the three months ended March 31, 2025, decreased five percent sequentially. The overall decrease consisted of decreases of 13 percent and two percent from our South Texas and Midland Basin assets, respectively, partially offset by a six percent increase from our Uinta Basin assets. The decreases in average net daily equivalent production from our South Texas and Midland Basin assets were anticipated during the first quarter of 2025 as a result of no completion crews operating in South Texas during the fourth quarter of 2024, and the planned timing of well completions in the Midland Basin. These anticipated changes also reflect a shift in capital allocation to our Uinta Basin assets. Average net daily equivalent production increased 36 percent YTD 2025-over-YTD 2024 primarily driven by the addition of 38.4 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 South Texas and Midland Basin assets increased 10 percent and nine percent, respectively.
Current 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.
Previous wording
Our total realized price per BOE increased $3.61 sequentially as a result of increases in oil, gas and NGL benchmark prices. Our total realized price per BOE increased $4.90 YTD 2025-over-YTD 2024 as a result of a shift in our production mix towards more oil production, and increases in gas and NGL benchmark prices, slightly offset by a decrease in oil benchmark prices. For the three months ended March 31, 2025, December 31, 2024, and March 31, 2024, we recognized net gains on the settlement of our commodity derivative contracts of $0.44 per BOE, $1.17 per BOE, and $1.01 per BOE, respectively.
Current 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.
Previous wording
LOE per BOE increased 15 percent sequentially as a result of increases in certain operating costs including workover expense, and decreased average net daily equivalent production. LOE per BOE increased 11 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, which outpaced an increase in average net daily equivalent production. For the full-year 2025, we expect LOE per BOE to increase, compared with 2024, as our product mix continues to shift towards more oil production with our Uinta Basin assets, and as a result of 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
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.
Previous wording
Transportation costs per BOE decreased four percent sequentially primarily as a result of a decrease in average net daily equivalent production from our South Texas assets, slightly offset by an increase in average net daily equivalent production from our Uinta Basin assets. Transportation costs per BOE increased 89 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 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.
Previous wording
Production tax expense per BOE increased 16 percent sequentially primarily as a result of an increase in total realized price per BOE and a decrease in average net daily equivalent production. Production tax expense per BOE increased nine percent YTD 2025-over-YTD 2024, as a result of an increase in total realized price per BOE. Our overall production tax rate for the three months ended March 31, 2025, December 31, 2024, and March 31, 2024, was 4.4 percent, 4.1 percent, and 4.5 percent, 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 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.
Previous wording
Ad valorem tax expense per BOE increased sequentially as a result of final valuation assessments received during the three months ended December 31, 2024, that reduced expense in that period. Ad valorem tax expense per BOE decreased 38 percent YTD 2025-over-YTD 2024 primarily as a result of decreased oil prices impacting 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 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.
Previous wording
Depletion, depreciation, and amortization (“DD&A”) expense per BOE increased 12 percent sequentially, primarily driven by an increase in our DD&A rates as a result of the acquisition of our Uinta Basin assets. DD&A expense per BOE increased 21 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
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.
Previous wording
General and administrative (“G&A”) expense on a per BOE basis remained relatively flat sequentially, and decreased slightly YTD 2025-over-YTD 2024 primarily as a result of an increase in average net daily equivalent production. 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 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.
Previous wording
Refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2025, and December 31, 2024, and Between the Three Months Ended March 31, 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 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.
Previous wording
Average net daily equivalent production volumes decreased five percent, consisting of decreases of 13 percent and two percent from our South Texas and Midland Basin assets, respectively, partially offset by an increase of six percent from our Uinta Basin assets. As a result of increases in benchmark commodity prices, total realized price per BOE increased eight percent. The decrease in average net daily equivalent production volumes was offset by the increase in total realized price per BOE resulting in oil, gas, and NGL production revenue remaining flat sequentially. Oil, gas, and NGL production expense increased five percent, primarily driven by increases in ad valorem tax expense and LOE.
Current wording
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 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 three months ended March 31, 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 six months ended June 30, 2025, and 2024:
Previous wording
(1)Amounts reflect Uinta Basin activity for the three months ended March 31, 2025. There was no comparable activity for the three months ended March 31, 2024, as the Uinta Basin assets were acquired on October 1, 2024.
Current 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.
Previous wording
Average net daily equivalent production volumes increased 36 percent, primarily driven by the addition of 38.4 MBOE per day of production from our Uinta Basin assets. Average net daily equivalent production from our South Texas and Midland Basin assets increased 10 percent and nine percent, respectively. Oil, gas, and NGL production revenue increased 50 percent and oil, gas, and NGL production expense increased 64 percent, primarily driven by the addition of our Uinta Basin assets.
Current 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.
Previous wording
DD&A expense increased four percent sequentially, primarily driven by increases in our DD&A rates, partially offset by a decrease in average net daily equivalent production. DD&A expense increased 62 percent YTD 2025-over-YTD 2024 as a result of increased average net daily equivalent production, including the addition of production from our recently acquired 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 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.
Previous wording
Exploration expense decreased 28 percent sequentially, primarily due to a decrease in geological, geophysical, and other expenses. Exploration expense decreased 37 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 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.
Previous wording
Net derivative 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) 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.
Previous wording
Interest expense decreased four percent sequentially due to a decrease in our daily weighted-average revolving credit facility balance. Interest expense increased 103 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 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.
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Previous report — wording carried elsewhere
Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2025, and December 31, 2024, and Between the Three Months Ended March 31, 2025, and 2024