SM Energy Co: Form 10-Q for the period ended Sep 30, 2025

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”).

Overview of the Company

Merger with Civitas

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.

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.

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.

General Overview

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.

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.

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.

Market Trends and Uncertainties

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.

Historically, tariffs have led to increased costs for products exchanged in international trade, and have heightened global political tensions. Recent U.S. government policies, including new and higher tariffs on imported goods, have increased economic uncertainty. These tariffs, along with retaliatory tariffs from other countries, could lead to reduced trade resulting from increased costs for imported goods and decreased demand for U.S. exports, as well as reduced investment and technological exchange between major economies. These outcomes could negatively impact global economic conditions, financial market stability, and commodity prices. Volatility in political, trade, regulatory, and economic conditions could have a material adverse effect on our financial condition or results of operations. We are unable to reasonably estimate the period of time that these market conditions will exist or the extent to which they will impact our business, results of operations, and financial condition.

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.

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.

Areas of Operations

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.

Our South Texas assets are comprised of approximately 155,000 net acres located in Dimmit and Webb counties, Texas (“South Texas”). Our overlapping acreage position in South Texas covers a significant portion of the western Eagle Ford shale and Austin Chalk formations, and includes acreage across the oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction.

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.

Third Quarter 2025 Overview and Outlook for the Remainder of 2025

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.

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.

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.

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.

Operational and financial activities during the three months ended September 30, 2025, resulted in the following:

• 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.
• 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.
• 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.

Refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2025, and June 30, 2025, and Between the Nine Months Ended September 30, 2025, and 2024 below for additional discussion.

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.

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.

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.

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.

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.

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:

(1) As of December 31, 2024, the drilled but not completed well count included nine gross (nine net) wells that were not included in our five-year development plan as of December 31, 2024, eight of which were in the Eagle Ford shale.

(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.

(3) Adjustment primarily relates to the acquisition of additional working interest in existing drilled but not completed wells.

Production Results. The table below presents the disaggregation of our net production volumes by product type for each of our assets for the periods presented:

Note: Amounts may not calculate due to rounding.

(1) The Uinta Basin assets were acquired on October 1, 2024.

Refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2025, and June 30, 2025, and Between the Nine Months Ended September 30, 2025, and 2024 below for discussion of production.

Oil, Gas, and NGL Prices

Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period, before the effect of net derivative settlements. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials, and contracted pricing benchmarks for these products.

The following table summarizes commodity price data, as well as the effect of net derivative settlements, for the periods presented:

(1) Average OPIS price per barrel of NGL, historical or strip, assumes a composite barrel product mix of 42% ethane, 28% propane, 6% isobutane, 11% normal butane, and 13% natural gasoline. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.

Given the uncertainty surrounding global financial markets, we expect benchmark prices for oil, gas, and NGLs to remain volatile for the foreseeable future. In addition to supply and demand fundamentals, as global commodities, the prices for oil, gas, and NGLs are affected by real or perceived geopolitical risks in various regions of the world, as well as the relative strength of the United States dollar compared to other currencies. Additionally, our realized prices at local sales points have been and may continue to be affected by infrastructure capacity or outages in the areas of our operations and beyond. We cannot reasonably predict the timing or likelihood of any future volatility or the related impacts. Refer to Market Trends and Uncertainties above for additional discussion of factors impacting pricing.

The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of October 22, 2025, and September 30, 2025:

We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives, and decisions regarding entering into commodity derivative contracts are overseen by a financial risk management committee consisting of certain senior executive officers and finance personnel. We make decisions about the amount of our expected production that we cover by derivatives based on the amount of debt on our balance sheet, the level of capital commitments and long-term obligations we have in place, and the terms and futures prices that are made available by our approved counterparties. With our current commodity derivative contracts, we believe we have partially reduced our exposure to volatility in commodity prices and basis differentials in the near term. Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil and gas prices while also setting a price floor below which we are insulated from further price decreases. Refer to Note 7 - Derivative Financial Instruments in Part I, Item 1 of this report and to Commodity Price Risk in Overview of Liquidity and Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.

Financial Results of Operations and Additional Comparative Data

The tables below provide information regarding selected production and financial information for the three months ended September 30, 2025, and the preceding three quarters:

(in millions)

Selected Performance Metrics

Note: Amounts may not calculate due to rounding.

Overview of Selected Production and Financial Information, Including Trends

33

(1) Amounts and percentage changes may not calculate due to rounding.

(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.

(3) Refer to Note 9 - Earnings Per Share in Part I, Item 1 of this report for additional discussion.

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.

We present certain information on a per BOE basis in order to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis and discussion.

Our 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.

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.

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.

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.

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.

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.

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.

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.

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

Refer to Overview of Selected Production and Financial Information, Including Trends above for additional discussion, including discussion of trends on a per BOE basis.

Average net daily equivalent production, production revenue, and production expense

Sequential Quarterly Changes. The following table presents changes in our average net daily equivalent production; oil, gas, and NGL production revenue; and oil, gas, and NGL production expense, by area, between the three months ended September 30, 2025, and June 30, 2025:

(in millions)

(in millions)

Note: Amounts may not calculate due to rounding.

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.

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:

(in millions)

(in millions)

Note: Amounts may not calculate due to rounding.

(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.

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.

Depletion, depreciation, and amortization

(in millions)

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.

Exploration

(in millions)

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.

General and administrative

(in millions)

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.

Net derivative gain

(in millions)

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.

Interest expense

(in millions)

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.

Income tax expense

(in millions, except tax rate)

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.

The effects of changes in tax laws are recognized in the period of enactment. On July 4, 2025, the OBBBA was enacted into law and includes, among other things, tax reform provisions that amend, eliminate, and extend tax rules under the Inflation Reduction Act and Tax Cuts and Jobs Act. During the third quarter of 2025, we recorded the impacts of the OBBBA on our full-year income tax expense, which resulted in a decrease to the current portion of income tax expense. This change reflects the impacts of the reinstatement of 100 percent bonus depreciation on tangible assets; the immediate expensing of qualified R&D expenditures and the expensing of unamortized, previously capitalized, qualified R&D expenditures; and a less restrictive limitation on the business interest expense deduction. Additionally, the OBBBA allows for the deduction of intangible drilling costs from adjusted financial statement income (“AFSI”) when determining whether a company is subject to and liable for the Corporate Alternative Minimum Tax (“CAMT”). As a result, we do not expect to become subject to or liable for the CAMT for the foreseeable future, notwithstanding other factors that may impact our AFSI.

Refer to Note 4 - Income Taxes in Part I, Item 1 of this report, and to the Risk Factors section in Part 1, Item 1A of our 2024 Form 10-K for additional discussion.

Overview of Liquidity and Capital Resources

Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan while continuing to meet our financial obligations, including near-term maturities of our outstanding Senior Notes. We continue to manage the duration and level of our drilling and completion service commitments in order to maintain flexibility with regard to our activity level and capital expenditures.

Sources of Cash

During the nine months ended September 30, 2025, we primarily funded our capital expenditures and return of capital program with cash flows from operating activities. For the remainder of 2025, we expect to fund our capital expenditures and return of capital program with cash flows from operations, with any remaining cash needs being funded by borrowings under our revolving credit facility. Although we expect cash flows from these sources to be sufficient for the remainder of 2025, we may also elect to raise funds through new debt or equity offerings or from other sources of financing. If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our current stockholders could be diluted, and these newly issued securities may have rights, preferences, or privileges senior to those of certain existing stockholders and bondholders. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs.

Our credit ratings affect the availability of, and cost for us to borrow, additional funds. Any future downgrades in our credit ratings could make it more difficult or expensive for us to borrow additional funds. All of our sources of liquidity can be affected by the general conditions of the broader economy, force majeure events, fluctuations in commodity prices, operating costs, interest rate changes, tax law changes, and volumes produced, all of which affect us and our industry.

We have no control over the market prices for oil, gas, or NGLs, although we may be able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of commodity derivative contracts as part of our financial risk management program. Commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise over the price established by the commodity derivative contract. Refer to Note 7 - Derivative Financial Instruments in Part I, Item 1 of this report for additional information about our commodity derivative contracts currently in place.

Credit Agreement

Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $3.0 billion. As of September 30, 2025, the borrowing base and aggregate revolving lender commitments under our Credit Agreement were $3.0 billion and $2.0 billion, respectively. The borrowing base is subject to regular, semi-annual redetermination, and considers the value of both our proved oil and gas properties reflected in our most recent reserve report and commodity derivative contracts, each as determined by our lender group. Subsequent to September 30, 2025, our lender group reaffirmed our borrowing base and aggregate lender commitments at existing amounts. The next borrowing base redetermination is scheduled to occur on April 1, 2026. In connection with the semi-annual borrowing base redetermination, we entered into the Third Amendment with our lenders to amend the springing maturity provision of the Credit Agreement to provide a more flexible structure based on the amount of our short-term debt outstanding and our borrowing availability. No individual bank participating in our Credit Agreement represents more than 10 percent of the lender commitments under the Credit Agreement. We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement. We were in compliance with all financial and non-financial covenants under the Credit Agreement as of September 30, 2025, and through the filing of this report.

The following table summarizes our daily weighted-average revolving credit facility balance during the periods presented:

(in millions)

The amount we borrow under our revolving credit facility is impacted by cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities including open market debt repurchases, debt redemptions, and repayment of scheduled debt maturities, other financing activities, and our capital expenditures, including acquisitions.

Refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion, as well as the presentation of the outstanding balance, total amount of letters of credit, and available borrowing capacity under the Credit Agreement as of October 22, 2025, September 30, 2025, and December 31, 2024.

Weighted-Average Interest and Weighted-Average Borrowing Rates

Our weighted-average interest rate includes paid and accrued interest, fees on the unused portion of the aggregate revolving lender commitment amount under the Credit Agreement, letter of credit fees, and the non-cash amortization of deferred financing costs. Our weighted-average borrowing rate includes paid and accrued interest only.

The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the periods presented:

38

Our weighted-average interest and weighted-average borrowing rate each remained relatively flat sequentially, and each increased YTD 2025-over-YTD 2024 as a result of the issuance of our 2029 Senior Notes and 2032 Senior Notes, which have greater outstanding aggregate principal balances and higher interest rates than our other outstanding Senior Notes, and as a result of borrowings under our revolving credit facility. We expect our weighted-average interest rate and weighted-average borrowing rate to increase slightly for the full-year 2025 compared with 2024.

Our weighted-average interest rate and weighted-average borrowing rate are affected by the occurrence and timing of long-term debt issuances and redemptions and the average outstanding balance under our revolving credit facility. Additionally, our weighted-average interest rate is affected by the fees paid on the unused portion of our aggregate revolving lender commitments.

Uses of Cash

We use cash for the development, exploration, and acquisition of oil and gas properties; for the payment of operating and general and administrative costs, income taxes, debt obligations, including interest and early repayments or redemptions, and dividends; and for repurchases of shares of our outstanding common stock under the Stock Repurchase Program. Expenditures for the development, exploration, and acquisition of oil and gas properties are the primary use of our capital resources. During the nine months ended September 30, 2025, we spent $1.22 billion on capital expenditures. This amount differs from the costs incurred amount of $1.17 billion for the nine months ended September 30, 2025, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, acquisitions of oil and gas properties, and exploration overhead amounts.

The amount and allocation of our future capital expenditures will depend upon a number of factors, including our cash flows from operating, investing, and financing activities, our ability to execute our development program, inflation, and the number and size of acquisitions that we complete. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, tax law and other regulatory changes, and the timing and results of our exploration and development activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget and guidance to assess if changes are necessary based on current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors. Our capital program for 2025, excluding acquisitions, is expected to be approximately $1.375 billion and includes certain non-operated capital projects.

We may from time to time repurchase shares of our common stock, or repurchase or redeem all or portions of our outstanding debt securities, for cash, through exchanges for other securities, or a combination of both. Such repurchases or redemptions may be made in open market transactions, privately negotiated transactions, tender offers, pursuant to contractual provisions, or otherwise. Any such repurchases or redemptions will depend on our business strategy, prevailing market conditions, our liquidity requirements, contractual restrictions or covenants, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material.

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.

During the nine months ended September 30, 2025, and 2024, we repurchased and subsequently retired 0.4 million and 1.8 million shares, respectively, of our common stock at a total cost of $12.1 million and $84.0 million, respectively, excluding excise taxes, commissions, and fees. As of September 30, 2025, $487.9 million was available under the Stock Repurchase Program for repurchases of our common stock through December 31, 2027.

During the nine months ended September 30, 2025, and 2024, we paid $68.8 million and $62.1 million, respectively, in dividends to our stockholders. We currently intend to continue paying dividends to our stockholders for the foreseeable future, subject to our future earnings, our financial condition, covenants under our Credit Agreement and indentures governing each series of our outstanding Senior Notes, and other factors that could arise. The payment and amount of future dividends remain at the discretion of our Board of Directors.

On July 4, 2025, the OBBBA was enacted into law and we recorded the impacts of the OBBBA on our full-year income tax expense during the third quarter of 2025. As a result, we expect a reduction in the amount of cash we would have been required to pay for federal income taxes during 2025. Additional changes in federal and state income tax laws and other possible future legislation, including changes in the corporate tax rate, could have a material effect on our net cash provided by operating activities, income tax expense, tax receivable, and deferred tax liabilities. Refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2025, and June 30, 2025, and Between the Nine Months Ended September 30, 2025, and 2024 for discussion of the OBBBA.

Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2025, and 2024

The following tables present changes in cash flows between the nine months ended September 30, 2025, and 2024, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying statements of cash flows in Part I, Item 1 of this report.

Operating activities

(in millions)

Net cash provided by operating activities increased for the nine months ended September 30, 2025, compared with the same period in 2024, primarily as a result of an increase of $482.8 million in cash received from oil, gas, and NGL production revenue net of transportation costs and production taxes and an increase of $31.9 million in cash received on settled derivative trades, partially offset by an increase of $131.5 million in cash paid for LOE, ad valorem taxes, and certain G&A expenses and an increase of $81.4 million of cash paid for interest. These changes are largely a result of the Uinta Basin Acquisition. Net cash provided by operating activities is also affected by working capital changes and the timing of cash receipts and disbursements.

Investing activities

(in millions)

Net cash used in investing activities increased for the nine months ended September 30, 2025, compared with the same period in 2024, as a result of a $264.6 million increase in capital expenditures and $21.5 million of cash paid related to acquisition activity, primarily post-closing adjustments related to final settlement of the Uinta Basin Acquisition during the first quarter of 2025.

Financing activities

(in millions)

Net cash used in financing activities for the nine months ended September 30, 2025, primarily related to $68.8 million of dividends paid to our stockholders, net repayments of $68.5 million under our revolving credit facility, and $12.8 million cash paid, including excise taxes, commissions, and fees, to repurchase and subsequently retire 0.4 million shares of our common stock under the Stock Repurchase Program.

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.

Interest Rate Risk

We are exposed to market and credit risk due to the floating interest rate associated with any outstanding balance under our revolving credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period of up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the revolving credit facility’s fair value but will not affect results of operations or cash flows. Conversely, for the portion of the revolving credit facility that has a floating interest rate, interest rate changes will not affect the fair value, but will affect future results of operations and cash flows. Changes in interest rates do not affect the amount of interest we pay on our fixed-rate Senior Notes, but can affect their fair values. As of September 30, 2025, our outstanding principal amount of fixed-rate debt totaled $2.7 billion, and we had no floating-rate debt outstanding. Refer to Note 8 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion on the fair values of our Senior Notes.

Commodity Price Risk

The prices we receive for our oil, gas, and NGL production directly affect our revenue, profitability, access to capital, ability to return capital to our stockholders, and future rate of growth. Oil, gas, and NGL prices are subject to unpredictable fluctuations resulting from a variety of factors that are typically beyond our control, including changes in supply and demand associated with the broader macroeconomic environment, constraints on gathering systems, processing facilities, pipelines, rail systems and other transportation systems, and weather-related events. The markets for oil, gas, and NGLs have been volatile, especially over the last decade, and remain subject to high levels of uncertainty and volatility. The realized prices we receive at local sales points for our production have been and may continue to be affected by infrastructure capacity or outages in the areas of our operations and beyond, and also depend on numerous factors that are typically beyond our control. Based on our production for the nine months ended September 30, 2025, a 10 percent decrease in our average realized oil, gas, and NGL prices would have reduced our oil, gas, and NGL production revenue by approximately $198.1 million, $28.2 million, and $17.2 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the nine months ended September 30, 2025, would have offset the declines in oil, gas, and NGL production revenue by approximately $77.9 million.

We enter into commodity derivative contracts in order to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of September 30, 2025, a 10 percent increase or decrease in the forward curves associated with our oil, gas, and NGL commodity derivative instruments would have changed our net derivative positions for these products by approximately $79.8 million, $31.7 million, and $0.9 million, respectively.

Off-Balance Sheet Arrangements

We have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPE”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.

We evaluate our transactions to determine if any variable interest entities exist. If we determine that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements. We have not been involved in any unconsolidated SPE transactions during the nine months ended September 30, 2025, or through the filing of this report.

Critical Accounting Estimates

Refer to the corresponding section in Part II, Item 7 and to Note 1 - Summary of Significant Accounting Policies included in Part II, Item 8 of our 2024 Form 10-K for discussion of our accounting estimates.

Accounting Matters

Refer to Note 1 - Summary of Significant Accounting Policies in Part I, Item 1 of this report for information on new authoritative accounting guidance.

Non-GAAP Financial Measures

Adjusted EBITDAX represents net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, amortization and asset retirement obligation liability accretion expense, exploration expense, property abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, and certain other items. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we believe provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Agreement based on adjusted EBITDAX ratios as further described in Note 5 - Long-Term Debt in the 2024 Form 10-K. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our revolving credit facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failed to comply with the covenants that establish a maximum permitted ratio of total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX, we would be in default, an event that would prevent us from borrowing under our revolving credit facility and would therefore materially limit a significant source of our liquidity. In addition, if we are in default under our revolving credit facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures governing each series of our outstanding Senior Notes would be entitled to exercise all of their remedies for default.

The following table provides reconciliations of our net income (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented:

(in thousands)

(1) Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.

(2) For the three and nine months ended September 30, 2024, amounts exclude certain capital expenditures primarily related to one well deemed non-commercial.

The information required by this item is provided under the captions Interest Rate Risk and Commodity Price Risk in Item 2 above, as well as under the section entitled Summary of Oil, Gas, and NGL Derivative Contracts in Place in Note 7 - Derivative Financial Instruments in Part I, Item 1 of this report and is incorporated herein by reference. Also refer to the information under Interest Rate Risk and Commodity Price Risk in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our 2024 Form 10-K.

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including our Chief Executive Officer (Principal Executive Officer) and our Chief Financial Officer (Principal Financial Officer), as appropriate, to allow for timely decisions regarding required disclosure.

Our management, including our Chief Executive Officer and our Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our Disclosure Controls are effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There have been no changes during the third quarter of 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Risks Related to the Pending Merger

The Company’s stockholders and Civitas’ stockholders, in each case as of immediately prior to the Merger, will have reduced ownership in the combined company.

Based on the number of issued and outstanding shares of Civitas common stock as of October 31, 2025, and the number of issued and outstanding Civitas equity awards currently estimated to be payable in shares of the Company’s common stock in connection with the Merger, the Company anticipates issuing approximately 126.3 million shares of Company common stock pursuant to the Merger Agreement. The actual number of shares of Company common stock to be issued pursuant to the Merger Agreement will be determined at the completion of the Merger based on the number of shares of Civitas common stock issued and outstanding immediately prior to such time and the number of issued and outstanding Civitas equity awards payable in shares of Company common stock in connection with the Merger. The issuance of these new shares could have the effect of depressing the market price of the Company’s common stock, through dilution of earnings per share or otherwise. Any dilution of, or delay of any accretion to, the Company’s earnings per share could cause the price of the Company’s common stock to decline or increase at a reduced rate.

The consummation of the Merger is subject to a number of conditions that may not be satisfied or completed on a timely basis or at all. Accordingly, there can be no assurance as to when or if the Merger will be completed, and the failure to complete the Merger could have a material adverse effect on our business, financial condition, or results of operations.

Although we expect to complete the Merger in the first quarter of 2026, there can be no assurances as to the exact timing of the closing or that the Merger will be completed at all. The consummation of the Merger is subject to the satisfaction or waiver of a number of conditions contained in the related Merger Agreement, including, among others, approval by the Company’s and Civitas’ shareholders and the receipt of required regulatory approvals. Such conditions, some of which are beyond our control, may not be satisfied or waived in a timely manner or at all and therefore make the completion and timing of the Merger uncertain. In addition, the Merger Agreement contains certain termination rights for both parties, which if exercised will also result in the Merger not being consummated. Any such termination or any failure to otherwise complete the Merger could result in various consequences, including, among others: our business being adversely impacted by the failure to pursue other beneficial opportunities due to the time and resources committed by our management to the Merger, without realizing any of the benefits of completing the Merger; being required to pay our legal, accounting and other expenses relating to the Merger; the market price of our common stock being adversely impacted to the extent that the current market price reflects a market assumption that the Merger will be completed; and negative reactions from the financial markets and customers that may occur if the anticipated benefits of the Merger are not realized. Such consequences could have a material adverse effect on our business, financial condition, or results of operations.

The Merger Agreement restricts the Company's ability to pursue alternatives to the Merger.

The Merger Agreement contains provisions that restrict the ability of the Company to undertake certain business combinations with a party other than Civitas. In addition, the Company will be required to pay a termination fee of approximately $79.0 billion to Civitas if (i) the Merger Agreement is terminated by Civitas because the Company materially breached the terms of the Merger Agreement, (ii) an acquisition proposal or offer for a competing transaction had been publicly announced or communicated to the Company’s stockholders or board of directors between the signing and termination of the Merger Agreement and (iii) the Company engages in certain competing transactions within 12 months after the termination of the Merger Agreement.

Even if the Merger is completed, we may be unable to successfully integrate Civitas’ business into our business or achieve the anticipated benefits of the Merger, which may have a material adverse effect on our business, financial condition or results of operations.

The success of the Merger depends in part on whether we can complete the integration of the Civitas assets that we have not previously operated into our existing business in an efficient and effective manner, and there can be no assurance that we will be able to successfully integrate or otherwise realize the anticipated benefits of the Merger. The integration process may result in the disruption of ongoing business and there could be potential unknown liabilities and unforeseen expenses associated with the Merger that were not discovered in the course of performing due diligence. The integration may also require significant time and focus from management following the Merger that may disrupt our business and results of operations. Potential risks or difficulties include, among others:

• complexities associated with integrating our existing complex systems, technologies and other workflows with new assets;
• the inability to retain the services of key management and personnel;
• the accuracy of our assessments of the assets acquired in the Merger, including recoverable reserves, transportation costs and availability, drilling and completion equipment cost and availability, regulatory, permitting, and related matters;
• establishing business relationships with new third party contractors and other service providers with whom we have no prior experience; and
• potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the Merger.

Any of these issues could adversely affect our ability to maintain relationships with customers, suppliers, employees, and other constituencies. We may fail to realize the anticipated benefits expected from the Merger. The success of the Merger will depend, in significant part, on our ability to successfully complete the integration of the acquired assets, grow the revenue, and realize the anticipated strategic benefits from the Merger. The anticipated benefits of the Merger may not be realized fully or at all or may take longer to realize than expected. Actual operating, technological, strategic, and revenue opportunities, if achieved at all, may be less significant than expected or may take longer to achieve than anticipated. If we are not able to realize the anticipated benefits expected from the Merger within the anticipated timing or at all, our business and operating results may be adversely affected.

We have incurred additional costs in connection with the Merger, which will continue during 2025 and for a portion of 2026.

During the three months ended September 30, 2025, we incurred non-recurring costs associated with the Merger, and we expect to continue to incur such costs during 2025 and for a portion of 2026. A substantial majority of non-recurring expenses consist of transaction costs and include, among others, fees paid to financial, legal, accounting, and other advisors. Although we expect that the elimination of any duplicative costs, as well as the realization of expected benefits related to the integration of the Civitas assets, should allow us to offset these transaction costs over time, this net benefit may not be achieved in the near term or at all.

Securities class action and derivative lawsuits may be brought against us in connection with the Merger, which could result in substantial costs.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger, or other business combination agreements. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition.

There have been no other material changes to the risk factors as previously disclosed in our 2024 Form 10-K.