SM Energy Co (SM)

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion includes forward-looking statements. Refer to the Cautionary Information about Forward-Looking Statements section of this report for important information about these types of statements.

Overview of the Company

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. 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.

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 northeastern 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, including the Uinta Basin Acquisition, 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. Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for additional discussion and for the definition of the Uinta Basin Acquisition.

We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; building and maintaining partnerships with our stakeholders by investing in and connecting with the communities where we live and work; and transparency in reporting our progress in these areas. The Environmental, Social and Governance Committee of our Board of Directors oversees, among other things, the effectiveness of our ESG 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. Refer to our Definitive Proxy Statement on Schedule 14A for the 2025 annual meeting of stockholders to be filed within 120 days from December 31, 2024, for additional discussion of our compensation programs.

We are affected by global commodity and financial markets that remain subject to heightened levels of uncertainty and volatility. Key factors contributing to market fluctuations include ongoing oil production curtailment agreements among OPEC+, fluctuations in oil and gas demand from China, War and Geopolitical Instability, United States Federal Reserve monetary policy, shipping channel constraints and disruptions, tariffs or trade restrictions, and changes in global oil inventory in storage. These factors have driven commodity price volatility, contributed to instances of supply chain disruptions 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. Despite continuing uncertainty, we expect to maximize the value of our high-quality asset base and sustain strong operational performance and financial stability. We remain focused on generating cash flows to enable us to return capital to stockholders and reduce our debt.

Outlook

We expect our total 2025 capital program to be approximately $1.3 billion, excluding acquisitions, which we expect to fund with cash flows from operations, with any remaining cash needs being funded by borrowings under our revolving credit facility. We plan to focus our 2025 capital program on highly economic oil development projects in our Midland Basin, South Texas, and Uinta Basin assets. Refer to Outlook in Part I, Items 1 and 2 of this report for additional discussion.

2024 Financial and Operational Highlights

During 2024:

•We expanded our operations into Utah upon the completion of the Uinta Basin Acquisition during the fourth quarter of 2024. Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for additional discussion and the definition of the Uinta Basin Acquisition.

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•We issued a combined $1.5 billion of aggregate principal amount of our 2029 Senior Notes and 2032 Senior Notes and redeemed the remaining $349.1 million aggregate principal amount outstanding of our 2025 Senior Notes. Refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion.

•Our Board of Directors approved an increase to our fixed dividend to $0.80 per share annually, to be paid in quarterly increments of $0.20 per share, which commenced in the fourth quarter of 2024. We paid a net cash dividend of $0.74 per share, an increase from $0.60 per share paid during 2023. Refer to Note 3 – Equity in Part II, Item 8 of this report for additional discussion.

•During the first half of 2024, we repurchased and subsequently retired 1.8 million shares of our common stock at a cost of $84.0 million, excluding excise taxes, commissions, and fees. In June 2024, our Board of Directors re-authorized our existing Stock Repurchase Program, and as of December 31, 2024, $500.0 million remained available under the Stock Repurchase Program for repurchases of our common stock through December 31, 2027. Refer to Note 3 – Equity in Part II, Item 8 of this report for additional discussion.

Financial and Operational Results. Average net daily equivalent production for the year ended December 31, 2024, increased 12 percent to 170.5 MBOE, compared with 152.0 MBOE for 2023, as a result of strong well performance, an increased number of completions, and production from our Uinta Basin assets during the fourth quarter of 2024. The increase primarily consisted of increases of seven percent and six percent from our Midland Basin and South Texas assets, respectively, and 9.1 MBOE of production from our Uinta Basin assets.

Realized prices for oil and gas decreased two percent and 27 percent, respectively, for the year ended December 31, 2024, compared with 2023, as a result of decreases in oil and gas benchmark commodity prices. Realized price for NGLs remained flat for the year ended December 31, 2024, compared with 2023. Total realized price per BOE remained flat for the year ended December 31, 2024, compared with 2023, primarily driven by a 24 percent increase in oil production, offset by decreases in oil and gas benchmark commodity prices. Oil, gas, and NGL production revenue increased 13 percent to $2.7 billion for the year ended December 31, 2024, compared with $2.4 billion for 2023, primarily as a result of the timing of well completions, strong well performance, and production from our Uinta Basin assets during the fourth quarter of 2024. Oil, gas, and NGL production expense of $10.21 per BOE for the year ended December 31, 2024, remained flat, compared with 2023.

We recorded net derivative gains of $50.0 million and $68.2 million for the years ended December 31, 2024, and 2023, respectively. These amounts include net derivative settlement gains of $68.7 million and $26.9 million for the years ended December 31, 2024, and 2023, respectively.

Operational activities during the year ended December 31, 2024, resulted in the following:

•Net cash provided by operating activities of $1.8 billion, compared with $1.6 billion for 2023.

•Net income of $770.3 million, or $6.67 per diluted share, compared with net income of $817.9 million, or $6.86 per diluted share for 2023.

•Adjusted EBITDAX, a non-GAAP financial measure, of $2.0 billion, compared with $1.7 billion for 2023. Refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to net income and net cash provided by operating activities.

•A 12 percent increase in total estimated net proved reserves as of December 31, 2024, from December 31, 2023, to 678.3 MMBOE, of which, 62 percent were liquids (oil and NGLs) and 60 percent were proved developed reserves. The increase primarily consisted of the acquisition of 103.2 MMBOE of estimated net proved reserves in the Uinta Basin and revisions of previous estimates of 74.7 MMBOE related to infill reserves in both our South Texas and Midland Basin programs, partially offset by 62.4 MMBOE of production during 2024 and the removal of 30.5 MMBOE of certain net proved undeveloped reserves cases that are no longer expected to be developed within the five-year period from initial booking, as a result of the reallocation of capital to include our Uinta Basin assets. Our proved reserve life index remained flat at 10.9 years as of December 31, 2024, and 2023. Refer to Reserves in Part I, Items 1 and 2 of this report for additional discussion. The standardized measure of discounted future net cash flows was $7.3 billion as of December 31, 2024, compared with $6.3 billion as of December 31, 2023, which was an increase of 16 percent year-over-year primarily driven by the Uinta Basin Acquisition, partially offset by decreases in oil and gas benchmark commodity prices during 2024. Refer to Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion.

Operational Activities. During 2024, successful operational execution drove strong well performance and capital efficiency across our asset portfolio. Our continued success in both our Midland Basin and South Texas programs is attributable to our top-tier assets and technical teams, and our commitment to geoscience, technology, and innovation. During the fourth quarter of 2024, we began integrating our Uinta Basin assets where we focused on delineation and development.

In our Midland Basin program, we averaged four drilling rigs and one completion crew during 2024. Average net daily equivalent production volumes increased year-over-year by seven percent to 80.5 MBOE. Costs incurred during 2024 totaled

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$720.9 million, or 21 percent, of our total 2024 costs incurred. Drilling and completion activities focused on developing formations within our RockStar, Sweetie Peck, and Klondike assets.

In our South Texas program, we averaged two drilling rigs and one completion crew during 2024. Average net daily equivalent production volumes increased year-over-year by six percent to 81.0 MBOE. Costs incurred during 2024 totaled $478.3 million, or 14 percent, of our total 2024 costs incurred. Drilling and completion activities were primarily focused on delineating and developing the Austin Chalk formation.

In our Uinta Basin program, we averaged three drilling rigs and one completion crew during the fourth quarter of 2024. Average net daily equivalent production volumes totaled 36.1 MBOE for the fourth quarter of 2024, or 9.1 MBOE if calculated over the full year 2024. Costs incurred during 2024 totaled $2.3 billion, or 65 percent, of our total 2024 costs incurred, of which, over $2.1 billion related to acquisition costs. Drilling and completion activities primarily focused on delineating and developing the Lower Green River and Wasatch formations.

The table below provides a summary of changes in our drilled but not completed well count and current year drilling, completion, and acquisition activity in our operated programs for the year ended December 31, 2024:

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Note: Amounts may not calculate due to rounding.

(1)    As of December 31, 2023, and 2024, the drilled but not completed well count included nine gross (nine net) wells that were not included in our five-year development plan, eight of which were in the Eagle Ford shale.

(2)    We acquired these drilled but not completed wells as part of the Uinta Basin Acquisition on October 1, 2024. All drilling and completion activity presented in the table above for the Uinta Basin occurred during the fourth quarter of 2024. Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for additional discussion and the definition of the Uinta Basin Acquisition.

Costs Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, are summarized as follows:

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(1)    Refer to the caption Costs Incurred in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.

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Production Results. The table below presents the disaggregation of our net production volumes by product type for each of our assets for the year ended December 31, 2024:

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Note: Amounts may not calculate due to rounding.

Net equivalent production increased 12 percent for the year ended December 31, 2024, compared with 2023, comprised of increases of seven percent and six percent from our Midland Basin and South Texas assets, respectively, and 3.3 MMBOE of production during the fourth quarter of 2024 from our Uinta Basin assets. Refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between 2024 and 2023 and Between 2023 and 2022 below for additional 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 years ended December 31, 2024, 2023, and 2022:

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(1)    Effective January 1, 2023, 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. For periods prior to 2023, average OPIS price per barrel of NGL, historical or strip, assumed a composite barrel product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline. These product mixes represent the industry standard composite barrel for the respective periods presented and do not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.

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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, production output from OPEC+, global shipping channel constraints and disruptions, fluctuations in oil and gas demand from China, War and Geopolitical Instability, changes in global oil inventory in storage, tariffs or trade restrictions, and the potential impacts of these issues on global commodity markets, 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 in the areas of our operations and beyond.

The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of January 31, 2025, and December 31, 2024:

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 II, Item 8 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 December 31, 2024, and the preceding three quarters:

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Note: Amounts may not calculate due to rounding.

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Selected Performance Metrics

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Note: Amounts may not calculate due to rounding.

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Overview of Selected Production and Financial Information, Including Trends

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

(2)    Net derivative settlements for the years ended December 31, 2024, 2023, and 2022, are included within the net derivative (gain) loss line item in the accompanying consolidated statements of operations (“accompanying statements of operations”).

(3)    Refer to Note 9 – Earnings Per Share in Part II, Item 8 of this report for additional discussion.

Average net daily equivalent production for the year ended December 31, 2024, increased 12 percent compared with 2023, as a result of an increased number of completions, strong well performance, and production from our Uinta Basin assets during the fourth quarter of 2024. Oil production as a percentage of total production increased to 47 percent in 2024 from 43 percent in 2023, as a result of increased oil production from both our Midland Basin and South Texas assets, in addition to oil production from our Uinta Basin assets. In 2025, we expect total production volumes and oil as a percentage of total production to each increase compared with 2024. Refer to Comparison of Financial Results and Trends Between 2024 and 2023 and Between 2023 and 2022 below for additional discussion.

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 realized price on a per BOE basis remained flat for the year ended December 31, 2024, compared with 2023, primarily because a 24 percent increase in oil production was offset by decreases in oil and gas benchmark commodity prices. For the years ended December 31, 2024, and 2023, we recognized net gains on the settlement of our commodity derivative contracts of $1.10 per BOE and $0.49 per BOE, respectively.

LOE on a per BOE basis remained flat for the year ended December 31, 2024, compared with 2023, as increases in labor costs and certain other operating costs were offset by an increase in total net equivalent production and a decrease in workover expense due to the timing of activity. For 2025, we expect LOE on a per BOE basis 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 on a per BOE basis 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.

Transportation costs on a per BOE basis increased nine percent for the year ended December 31, 2024, compared with 2023. This increase was due to a six percent increase in NGL production from our South Texas assets and 3.3 MMBOE of production from our Uinta Basin assets, both of which incur higher transportation costs than our Midland 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. For 2025, we expect transportation costs on a per BOE basis to increase, compared with 2024, as a result of the addition of our Uinta Basin assets.

Production tax expense on a per BOE basis for the year ended December 31, 2024, decreased two percent compared with 2023, primarily as a result of a decrease in the realized price of gas. Our overall production tax rate was 4.3 percent and 4.4 percent for the years ended December 31, 2024, and 2023, respectively. We expect that our Uinta Basin assets will incur a lower production tax rate compared to 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 on a per BOE basis decreased 16 percent for the year ended December 31, 2024, compared with 2023, as a result of changes to the assessed values of our producing properties due to decreased commodity price assumptions used in the current year valuation, and increased net equivalent production. 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 can be impacted by changes in tax laws.

Depletion, depreciation, and amortization (“DD&A”) expense on a per BOE basis increased four percent for the year ended December 31, 2024, compared with 2023, due to a shift in production mix to our Uinta Basin assets. Our Midland Basin and Uinta Basin assets have higher DD&A rates than our South Texas assets. For 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. Our DD&A rate fluctuates as a result of changes in our production mix, changes in our total estimated proved reserve volumes, changes in capital allocation, impairments, acquisition and divestiture activity, and carrying cost funding and sharing arrangements with third parties.

General and administrative (“G&A”) expense on a per BOE basis increased two percent for the year ended December 31, 2024, compared with 2023, primarily as a result of increases in certain G&A expenses resulting from the Uinta Basin Acquisition and increased compensation expense, partially offset by a 12 percent increase in average net equivalent production. For 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 as a result of the Uinta Basin Acquisition and expected increases in compensation expense. We expect G&A expense on a per BOE basis to remain relatively flat, compared with 2024, as the expected increases in G&A expense on an absolute basis are expected to be mostly offset by increases in production. Certain components of G&A expense, and G&A expense on a per BOE basis, are impacted by

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the Company’s full year performance against performance targets established at the beginning of the year and, therefore, are subject to variability. Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for the definition of the Uinta Basin Acquisition.

Refer to Comparison of Financial Results and Trends Between 2024 and 2023 and Between 2023 and 2022 for additional discussion of operating expenses.

Comparison of Financial Results and Trends Between 2024 and 2023 and Between 2023 and 2022

Refer to Comparison of Financial Results and Trends Between 2023 and 2022 and Between 2022 and 2021 in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our 2023 Annual Report on Form 10-K, filed with the SEC on February 22, 2024, for a detailed discussion of certain comparisons of our financial results and trends for the year ended December 31, 2023, compared with the year ended December 31, 2022. Refer to Comparison of Financial Results and Trends Between 2022 and 2021 and Between 2021 and 2020 in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our 2022 Annual Report on Form 10-K, filed with the SEC on February 23, 2023, for a detailed discussion of certain comparisons of our financial results and trends for the year ended December 31, 2022, compared with the year ended December 31, 2021.

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

The following table presents the 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 years ended December 31, 2024, and 2023:

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Note: Amounts may not calculate due to rounding.

Average net daily equivalent production volumes for the year ended December 31, 2024, increased 12 percent compared with 2023, comprised of a seven percent increase from our Midland Basin assets, a six percent increase from our South Texas assets, and 9.1 MBOE of production from our Uinta Basin assets. As a result of decreases in benchmark oil and gas prices, realized prices for oil and gas decreased two percent and 27 percent, respectively, while the realized price for NGLs remained flat. The 13 percent increase in oil, gas, and NGL production revenue is primarily a result of the increase in average net daily equivalent production volumes. Oil, gas, and NGL production expense for the year ended December 31, 2024, increased 13 percent compared with 2023, as activity related to our Uinta Basin assets contributed to increases in transportation costs, LOE, and production tax expense.

The following table presents the 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 years ended December 31, 2023, and 2022:

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Note: Amounts may not calculate due to rounding.

Average net daily equivalent production volumes for the year ended December 31, 2023, increased five percent compared with 2022, comprised of a 20 percent increase from our South Texas assets, partially offset by a seven percent decrease from our Midland Basin assets. As a result of decreases in benchmark commodity prices, realized prices for oil, gas, and NGLs decreased 19 percent, 61 percent, and 35 percent, respectively, resulting in a 29 percent decrease in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense for the year ended December 31, 2023, decreased nine percent compared with 2022, primarily driven by decreases in production taxes and transportation costs, partially offset by an increase in LOE.

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

Depletion, depreciation, and amortization

DD&A expense for the year ended December 31, 2024, increased 17 percent compared with 2023, primarily as a result of a combination of increased average net daily equivalent production, including the addition of production from our Uinta Basin assets during the fourth quarter of 2024, and a shift in production mix to our Uinta Basin assets. Our Midland Basin and Uinta Basin assets have higher DD&A rates than our South Texas assets. DD&A expense for the year ended December 31, 2023, increased 14 percent compared with 2022, primarily as a result of inflation and a five percent increase in average net daily equivalent production volumes, partially offset by a shift in production mix due to higher activity in our South Texas assets, which have a lower DD&A rate than our Midland Basin assets. Refer to Overview of Selected Production and Financial Information, Including Trends above for discussion of DD&A expense on a per BOE basis.

Exploration

Exploration expense increased eight percent for the year ended December 31, 2024, compared with 2023, primarily as a result of an increase in geological and geophysical expenses related to our Uinta Basin assets. 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

G&A expense increased 14 percent for the year ended December 31, 2024, compared with 2023, primarily as a result of increases in certain G&A expenses resulting from the Uinta Basin Acquisition and increased compensation expense. Refer to Overview of Selected Production and Financial Information, Including Trends above for discussion of G&A expense, including G&A expense on a per BOE basis, and to Note 17 – Acquisitions in Part II, Item 8 of this report for the definition of the Uinta Basin Acquisition.

Net derivative (gain) loss

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

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prices to result in net derivative gains, as measured against our derivative contract prices. Refer to Note 7 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.

Interest expense

Interest expense increased 54 percent for the year ended December 31, 2024, compared with 2023, as a result of the issuance of our 2029 Senior Notes and 2032 Senior Notes during 2024, an increase in interest expense associated with borrowings under our revolving credit facility, and a $9.0 million fee that was paid to secure firm commitments for up to $1.2 billion of senior unsecured 364-day bridge term loans (“Bridge Facility”) in connection with the Uinta Basin Acquisition. We did not draw on the Bridge Facility, and after issuance of the 2029 Senior Notes and 2032 Senior Notes on July 25, 2024, we terminated the Bridge Facility, and the associated fees were recognized as interest expense. 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 due to the timing and amount of borrowings under our revolving credit facility. Refer to Overview of Liquidity and Capital Resources below, Significant Developments in 2024 in Part I, Items 1 and 2 for the definitions of 2029 Senior Notes and 2032 Senior Notes, and to Note 5 – Long-Term Debt and Note 17 – Acquisitions in Part II, Item 8 of this report for additional discussion and definitions.

Interest income

Interest income increased for the year ended December 31, 2024, compared with 2023, primarily due to maintaining a higher average balance of our interest-bearing cash and cash equivalents as a result of the issuance of our 2029 Senior Notes and 2032 Senior Notes during the third quarter of 2024 resulting in excess cash prior to the Closing Date of the Uinta Basin Acquisition. Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for additional discussion and definitions.

Loss on extinguishment of debt

The redemption of our 2025 Senior Secured Notes during 2022 resulted in a net loss on extinguishment of debt of $67.2 million, which included $33.5 million of premium paid, $26.3 million of accelerated expense recognition of the unamortized debt discount, and $7.4 million of accelerated expense recognition of the unamortized deferred financing costs. Refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion and the definition of 2025 Senior Secured Notes.

Income tax expense

Our effective tax rate in 2023 benefited from credits claimed as the result of the completion of a multi-year research and development (“R&D”) credit study. Excess tax deficiencies from stock-based compensation awards offset limits on expensing of certain

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covered individual’s compensation, net apportionment changes and other permanent expense items reduced the rate for each period presented. We benefited from the release of a valuation allowance on certain deferred tax assets in 2022.

During 2024, we made federal estimated tax payments of $25.5 million and state tax payments, net of refunds, of $1.4 million.

Enactment of changes to federal income tax laws, including changes in the corporate tax rate, could have a material effect on our current tax expense, tax receivable, and deferred tax liabilities. Effective for tax years beginning after December 31, 2022, the IRA provides for a 15 percent corporate alternative minimum tax (“CAMT”) on corporations with average adjusted financial statement income over $1.0 billion for any three-year period preceding the tax year. While the final proposed regulations regarding the CAMT may impact our calculation, as of the filing of this report we do not anticipate that we will become subject to the CAMT in 2025. Refer to Overview of Liquidity and Capital Resources below and to the Risk Factors section in Part 1, Item 1A of this report.

Refer to Critical Accounting Estimates below and Note 4 – Income Taxes in Part II, Item 8 of this report for further 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 current financial obligations. 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

We expect to fund our 2025 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 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 existing stockholders and bondholders. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs.

During 2024, we issued our 2029 Senior Notes and 2032 Senior Notes. See below for discussion on how the net proceeds received were used, and to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion.

Our credit ratings affect the availability of, and cost for us to borrow, additional funds. One major credit rating agency upgraded our credit ratings following the close of the Uinta Basin Acquisition on October 1, 2024, citing our increased size and scale, increased inventory, increased oil percentage of expected production, strong operational performance, our priority of improving our leverage metrics, our ability to consistently generate cash flows, and our use of financial derivative instruments as part of our financial risk management program. Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for the definition of the Uinta Basin Acquisition.

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, and 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 II, Item 8 of this report for additional information about our commodity derivative contracts currently in place and the timing of settlement of those contracts.

Credit Agreement

Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $3.0 billion. As of December 31, 2024, 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. The next borrowing base redetermination date is scheduled to occur on April 1, 2025. 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, including covenants limiting dividend payments and requiring that we maintain certain financial ratios, as set forth in the Credit Agreement. We were in compliance with all financial and non-financial covenants as of December 31, 2024, and through the filing of this report. Refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion, as well as the presentation of the outstanding balance, total amount

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of letters of credit, and available borrowing capacity under the Credit Agreement as of January 31, 2025, December 31, 2024, and December 31, 2023.

Our daily weighted-average revolving credit facility balance was $56.7 million during the year ended December 31, 2024. We had no revolving credit facility borrowings during the year ended December 31, 2023, and through the third quarter of 2024. Cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities including open market debt repurchases, debt redemptions, repayment of scheduled debt maturities, other financing activities, and our capital expenditures, including acquisitions, all impact the amount we borrow under our revolving credit facility.

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 commitment amount under the Credit Agreement, letter of credit fees, the non-cash amortization of deferred financing costs, and for the portion of 2022 during which they were outstanding, the non-cash amortization of the discount related to the 2025 Senior Secured Notes, as defined in Note 5 – Long-Term Debt in Part II, Item 8 of this report. 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 years ended December 31, 2024, 2023, and 2022:

Our weighted-average interest rate and weighted-average borrowing rate each increased for the year ended December 31, 2024, compared with 2023, primarily as a result of the issuance of our 2029 Senior Notes and 2032 Senior Notes during 2024, which have greater outstanding aggregate principal balances and higher interest rates compared with our other outstanding Senior Notes and our 2025 Senior Notes that we redeemed during the third quarter of 2024, and as a result of borrowings under our revolving credit facility during the fourth quarter of 2024. Our weighted-average interest rate and weighted-average borrowing rate each decreased for the year ended December 31, 2023, compared with 2022, as a result of the redemptions of our 2024 Senior Notes and 2025 Senior Secured Notes during 2022. The rates disclosed in the table above for the year ended December 31, 2024, do not reflect the $9.0 million fee paid to secure the Bridge Facility in connection with the Uinta Basin Acquisition.

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 on 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. The rates disclosed in the above table do not reflect certain amounts associated with the repurchase or redemption of Senior Notes, such as the accelerated expense recognition of the unamortized deferred financing costs and unamortized discounts, as these amounts are netted against the associated gain or loss on extinguishment of debt. The 2024 Senior Notes were redeemed on February 14, 2022, the 2025 Senior Secured Notes were redeemed on June 17, 2022, and the 2025 Senior Notes were redeemed on August 26, 2024. After these dates, the weighted-average interest rate was no longer affected by the non-cash amortization of deferred financing costs or, for the 2025 Senior Secured Notes, the non-cash amortization of the discount.

Refer to Significant Developments in 2024 in Part I, Items 1 and 2 for the definitions of 2029 Senior Notes and 2032 Senior Notes, and to Note 5 – Long-Term Debt and Note 17 – Acquisitions in Part II, Item 8 of this report for additional discussion and definitions.

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 2024, we spent $3.4 billion on capital expenditures and on acquisitions of proved and unproved oil and gas properties. This amount differs from the costs incurred amount of $3.5 billion for the year ended December 31, 2024, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, and exploration overhead amounts. Refer to Costs Incurred in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion.

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,

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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.

Changes to the Internal Revenue Code (“IRC“) and federal income tax laws could increase our corporate income tax rate and eliminate or reduce current tax deductions, such as those for intangible drilling costs, depreciation of equipment costs, and other deductions which currently reduce our taxable income. The CAMT and other possible future legislation could reduce our net cash provided by operating activities resulting in a reduction of available funding. Refer to Comparison of Financial Results and Trends Between 2024 and 2023 and Between 2023 and 2022 above for additional discussion.

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.

During the years ended December 31, 2024, and 2023, we repurchased and subsequently retired 1.8 million shares and 6.9 million shares, respectively, of our common stock at a cost, excluding excise taxes, commissions, and fees, of $84.0 million and $228.0 million, respectively. As of December 31, 2024, $500.0 million remained available under the Stock Repurchase Program for repurchases of our common stock through December 31, 2027. Effective January 1, 2023, shares of common stock repurchased, net of shares of common stock issued, are subject to a one percent excise tax imposed by the IRA. We paid a minimal amount of excise tax related to common stock repurchases during 2024. Refer to Note 3 – Equity in Part II, Item 8 of this report for discussion of the Stock Repurchase Program.

During the years ended December 31, 2024, 2023, and 2022, we paid $85.0 million, $71.6 million, and $19.6 million, respectively, in dividends to our stockholders. Dividends paid were $0.74, $0.60, and $0.16 per share during the years ended December 31, 2024, 2023, and 2022, respectively. During 2024, our Board of Directors approved an 11 percent increase to our fixed dividend to $0.80 per share annually, to be paid in quarterly increments of $0.20 per share, which commenced in the fourth quarter of 2024. 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.

During 2024, we redeemed all of the $349.1 million of aggregate principal amount outstanding of our 2025 Senior Notes. Additionally, we used a portion of the net proceeds from the 2029 Senior Notes and 2032 Senior Notes, cash on hand, and borrowings under our revolving credit facility to fund our proportionate share of the Uinta Basin Acquisition. Refer to Significant Developments in 2024 in Part I, Items 1 and 2 for the definitions of 2029 Senior Notes and 2032 Senior Notes, and to Note 5 – Long-Term Debt and Note 17 – Acquisitions in Part II, Item 8 of this report for additional discussion and definitions.

Analysis of Cash Flow Changes Between 2024 and 2023 and Between 2023 and 2022

The following tables present changes in cash flows between the years ended December 31, 2024, 2023, and 2022, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying consolidated statements of cash flows (“accompanying statements of cash flows”) in Part II, Item 8 of this report.

Operating Activities

Net cash provided by operating activities increased for the year ended December 31, 2024, compared with 2023, primarily as a result of a $184.8 million increase in cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, and an increase of $62.4 million in cash received on settled derivative trades. These amounts were partially offset by an increase of $46.5 million in cash paid for G&A expense, LOE, and ad valorem taxes. Net cash provided by operating activities was also affected by the timing of payments made between us and XCL Resources related to activity occurring after the Closing Date of the Uinta Basin Acquisition. Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for additional discussion and definitions.

Net cash provided by operating activities decreased for the year ended December 31, 2023, compared with 2022, primarily as a result of a $937.3 million decrease in cash received from oil, gas, and NGL production revenues, net of transportation costs and

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production taxes, and an increase of $44.5 million in cash paid for LOE and ad valorem taxes, partially offset by a decrease of $749.3 million in cash paid on settled derivative trades and a $45.5 million decrease in cash paid for interest.

Net cash provided by operating activities is affected by working capital changes and the timing of cash receipts and disbursements.

Investing Activities

Net cash used in investing activities increased for the year ended December 31, 2024, compared with 2023, as a result of $2.1 billion of cash paid for the Uinta Basin Acquisition and a $321.2 million increase in capital expenditures.

Net cash used in investing activities increased for the year ended December 31, 2023, compared with 2022, as a result of a $109.5 million increase in capital expenditures and $109.9 million of cash paid to acquire proved and unproved oil and gas properties in the Midland Basin, including the acquisition of additional working interests in certain wells.

Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for additional discussion of acquisition activity and the definition of the Uinta Basin Acquisition.

Financing Activities

Net cash provided by financing activities increased during the year ended December 31, 2024, primarily related to net cash proceeds of $1.5 billion from the issuance of our 2029 Senior Notes and 2032 Senior Notes, and net borrowings under our revolving credit facility of $68.5 million, partially offset by $349.1 million of cash paid to redeem our 2025 Senior Notes. Additionally, we paid $86.1 million, including commission and fees, to repurchase and subsequently retire 1.8 million shares of our common stock under the Stock Repurchase Program, and paid $85.0 million of dividends to our stockholders.

Net cash used in financing activities during the year ended December 31, 2023, primarily consisted of $228.1 million of cash paid, including commission and fees, to repurchase and subsequently retire 6.9 million shares of our common stock under the Stock Repurchase Program, and $71.6 million of dividends paid to our stockholders.

Net cash used in financing activities during the year ended December 31, 2022, related to $480.2 million of cash paid, including premium, to redeem our 2025 Senior Secured Notes, and $104.8 million to redeem our 2024 Senior Notes. Additionally, we paid $57.2 million, including commission and fees, to repurchase and subsequently retire 1.4 million shares of our common stock under the Stock Repurchase Program, $25.1 million for the net share settlement of employee stock awards, and paid $19.6 million of dividends to our stockholders.

Refer to Note 3 – Equity in Part II, Item 8 of this report for additional discussion of our Stock Repurchase Program and Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion and definitions related to our debt transactions.

Interest Rate Risk

We are exposed to market and credit risk due to the floating interest rate associated with any outstanding balance on 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 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 December 31, 2024, our outstanding principal amount of fixed-rate debt totaled $2.7 billion and our floating-rate debt

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outstanding totaled $68.5 million. Refer to Note 8 – Fair Value Measurements in Part II, Item 8 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 related to production output from OPEC+, fluctuations in oil and gas demand from China, global shipping channel constraints and disruptions, War and Geopolitical Instability, tariffs or trade restrictions, and the potential impacts of these issues on global commodity and financial markets. These circumstances have contributed to inflation, instances of supply chain disruptions, and fluctuations in interest rates, and could have further industry-specific impacts that may require us to adjust our business plan. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Refer to Risk Factors - Risks Related to Commodity Prices and Global Macroeconomics in Part I, Item 1A of this report. Based on our 2024 production, a 10 percent decrease in our average realized prices for oil, gas, and NGLs would have reduced our oil, gas, and NGL production revenues by approximately $218.7 million, $24.9 million, and $23.5 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the year ended December 31, 2024, would have offset the declines in oil, gas, and NGL production revenue by approximately $50.3 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 December 31, 2024, 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 $51.9 million, $23.4 million, and $1.7 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” or “SPEs”). Refer to Off-Balance Sheet Arrangements within Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report for additional discussion.

Critical Accounting Estimates

Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The preparation of these consolidated financial statements in conformity with GAAP requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses, as well as the disclosure of contingent assets and liabilities as of the date of our consolidated financial statements. We base our assumptions and estimates on historical experience and various other sources that we believe to be reasonable under the circumstances. Actual results may differ from the estimates we calculate as a result of changes in circumstances, global economics and politics, and general business conditions. A summary of our significant accounting policies is detailed in Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report. We have outlined below, those policies identified as being critical to the understanding of our business and results of operations and that require the application of significant management judgment.

Successful Efforts Method of Accounting. GAAP provides two alternative methods for the oil and gas industry to use in accounting for oil and gas producing activities. These two methods are generally known in our industry as the full cost method and the successful efforts method, and both methods are widely used. The methods are different enough that in many circumstances the same set of facts will provide materially different financial statement results within a given year. We have chosen the successful efforts method of accounting for our oil and gas producing activities. A more detailed description is included in Note 1 – Summary of Significant Accounting Policies of Part II, Item 8 of this report.

Oil and Gas Reserve Quantities. Our estimated proved reserve quantities and future net cash flows are critical to understanding the value of our business. They are used in comparative financial ratios and are the basis for significant accounting estimates in our consolidated financial statements, including the calculations of DD&A expense, impairment of proved and unproved oil and gas properties, asset retirement obligations, and purchase price allocations. Refer to Oil and Gas Producing Activities in Note 1 – Summary of Significant Accounting Policies of Part II, Item 8 of this report for additional discussion on our accounting policies impacted by estimated reserve quantities.

Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality differentials, and basis differentials, applicable to each period to the estimated quantities of proved reserves remaining to be produced as of the end of that period. Expected cash flows are discounted to present value using an appropriate discount rate. For example, the standardized measure of discounted future net cash flows calculation requires that a 10 percent discount rate be applied. Although reserve estimates are inherently imprecise and estimates of new discoveries and undeveloped

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locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves. We engage Ryder Scott, an independent reservoir evaluation consulting firm, to audit a minimum of 80 percent of our total calculated proved reserve PV-10. We expect proved reserve estimates will change as additional information becomes available and as commodity prices and operating and capital costs change. We evaluate and estimate our proved reserves each year end. It should not be assumed that the standardized measure of discounted future net cash flows (GAAP) or PV-10 (non-GAAP) as of December 31, 2024, is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based these measures on the unweighted arithmetic average of the first-day-of-the-month price of each month within the trailing 12-month period ended December 31, 2024. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimates. Refer to Risk Factors in Part I, Item 1A of this report for additional discussion.

If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, which would reduce future net income. Changes in DD&A rate calculations caused by changes in reserve quantities are made prospectively. In addition, a decline in reserve estimates may impact the outcome of our assessment of proved and unproved properties for impairment. Impairments are recorded in the period in which they are identified.

The following table presents information about proved reserve changes from period to period due to items we do not control, such as price, and from changes due to production history and well performance. These changes do not require a capital expenditure on our part, but may have resulted from capital expenditures we incurred to develop other estimated proved reserves.

____________________________________________

Note: Amounts may not calculate due to rounding.

(1)    For the year ended December 31, 2023, performance revisions consisted of positive revisions of 65.3 MMBOE resulting from changes to decline curve estimates based on reservoir engineering analysis and negative revisions of 28.0 MMBOE related to well performance.

As previously noted, commodity prices are volatile and estimates of reserves are inherently imprecise. Consequently, we expect to continue experiencing these types of changes.

We cannot reasonably predict future commodity prices, although we believe that together, the analyses below provide reasonable information regarding the impact of changes in pricing and trends on total estimated net proved reserves. The following table reflects the estimated MMBOE change and percentage change to our total reported estimated net proved reserve volumes from the described hypothetical changes:

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(1)    The change solely reflects the impact of a 10 percent decrease in SEC pricing to the total reported estimated net proved reserve volumes as of December 31, 2024, and does not include additional impacts to our estimated net proved reserves that may result from our internal intent to drill hurdles or changes in future service or equipment costs.

(2)    The change solely reflects the impact of replacing SEC pricing with the five-year average NYMEX strip pricing as of December 31, 2024, and does not include additional impacts to our estimated net proved reserves that may result from our internal intent to drill hurdles or changes in future service or equipment costs. As of December 31, 2024, SEC pricing was $75.48 per Bbl for oil, $2.13 per MMBtu for gas, and $28.29 per Bbl for NGLs, and five-year average NYMEX strip pricing was $65.69 per Bbl for oil, $3.72 per MMBtu for gas, and $26.08 per Bbl for NGLs.

(3)    The change solely reflects a 10 percent decrease in net proved undeveloped reserves as of December 31, 2024, and does not include any additional impacts to our estimated net proved reserves.

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Additional reserve information can be found in Reserves in Part I, Items 1 and 2 of this report, and in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.

Impairment of Proved Properties. Proved oil and gas properties are evaluated for impairment on a depletion pool-by-pool basis and reduced to fair value when events or changes in circumstances indicate that their carrying amount may not be recoverable. We estimate the expected future cash flows of our proved oil and gas properties and compare these undiscounted cash flows to the carrying amount to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the proved oil and gas properties to fair value (or discounted future cash flows). Management estimates future cash flows from all proved reserves and risk adjusted probable and possible reserves using various factors, which are subject to our judgment and expertise, and include, but are not limited to, commodity price forecasts, estimated future operating and capital costs, development plans, and discount rates to incorporate the risk and current market conditions associated with realizing the expected cash flows. We cannot predict when or if future impairment charges will be recorded because of the uncertainty in the factors discussed above. Despite any amount of future impairment being difficult to predict, based on our commodity price assumptions as of January 31, 2025, we do not expect any material proved oil and gas property impairments in the first quarter of 2025 resulting from commodity price impacts.

Accounting Matters

Refer to Recently Issued Accounting Guidance in Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report for information on new authoritative accounting guidance.

Environmental

We believe we are in substantial compliance with environmental laws and regulations and do not currently anticipate that material future expenditures will be required under the existing regulatory framework. However, environmental laws and regulations are subject to frequent changes, and we are unable to predict the impact that compliance with future laws or regulations, such as those currently being considered as discussed below, may have on future capital expenditures, liquidity, and results of operations.

Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. For additional information about hydraulic fracturing and related environmental matters, refer to Risk Factors – Risks Related to Government Regulations – Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Climate Change and Air Quality. In June 2013, President Obama announced a Climate Action Plan designed to further reduce GHG emissions and prepare the nation for the physical effects that may occur as a result of climate change. The Climate Action Plan targeted methane reductions from the oil and gas sector as part of a comprehensive interagency methane strategy. As part of the Climate Action Plan, on May 12, 2016, the EPA issued final regulations applicable to new, modified, or reconstructed sources that amended and expanded 2012 regulations for the oil and gas sector by, among other things, setting emission limits for volatile organic compounds (“VOCs” or “VOC”) and methane, a GHG, and added requirements for previously unregulated sources. The 2016 NSPS requires reduction of methane and VOCs from certain activities in oil and gas production, processing, transmission and storage and applies to facilities constructed, modified, or reconstructed after September 18, 2015. The regulation requires, among other things, GHG and VOC emission limits for certain equipment, such as centrifugal compressors and reciprocating compressors; semi-annual leak detection and repair for well sites and quarterly for boosting and garnering compressor stations and gas transmission compressor stations; control requirements and emission limits for pneumatic pumps; and additional requirements for control of GHGs and VOCs from well completions. On September 14, and 15, 2020, the EPA finalized amendments to the 2012 and 2016 NSPS that removed transmission and storage infrastructure from regulation of methane emissions and other VOCs, as well as removed methane control requirements. The portion of the 2020 amendments that removed the transmission and storage infrastructure from the regulations was disapproved by the Congressional Review Act in 2021. In November 2021, the EPA proposed to expand the requirements of the 2012 and 2016 NSPS and also include requirements for states to develop performance standards to control methane emissions from existing sources. In December 2022, the EPA issued a supplemental proposal to update, strengthen, and expand the 2021 proposed rules. The EPA finalized the rule in December 2023. In March 2024, the EPA announced a final rule that implements a waste emissions charge and new reporting requirements for facilities and wells completed after May 7, 2024.

States are also required to comply with the NAAQS. The oil and gas sector is often subjected to additional controls when areas within states are not attaining the ozone NAAQS as the VOCs emitted by the oil and gas sector are a precursor to ozone formation. The ozone NAAQS was set at 70 parts per billion (“ppb”) in 2015. In 2023, the EPA announced its plan to perform a full and complete review of the ozone NAAQS. The results of this review could result in changes to the ozone NAAQS which, if lowered, may result in additional actions by states requiring further emission controls and associated costs. Oil and gas facilities operating in areas that are determined to be out of compliance with the 70 ppb requirement or a lowered ozone NAAQS may be subject to increased emission controls and associated costs of compliance. As part of the integrated review process, the EPA held a workshop in May 2024 to discuss policy-relevant science that will inform the EPA’s current review of the air quality criteria and the NAAQS for ozone and related photochemical oxidants.

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The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and many of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. In addition, there have been international conventions and efforts to establish standards for the reduction of GHGs globally, including the Paris Agreement in December 2015. The conditions for entry into force of the Paris Agreement were met on October 5, 2016, and the Agreement went into force 30 days later on November 4, 2016. In January of 2025, President Trump issued an executive order that initiated the process for the United States to exit the Paris Agreement. At the United Nations Climate Change Conference in Glasgow in 2021, the United States and the European Union announced the Global Methane Pledge that aims to reduce methane emissions by 30 percent compared with 2020 levels.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition, and results of operations. Judicial challenges to new regulatory measures are likely and we cannot predict the outcome of such challenges. New regulatory suspensions, revisions, or rescissions and conflicting state and federal regulatory mandates may inhibit our ability to accurately forecast the costs associated with future regulatory compliance. Finally, scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere produce climate changes that likely have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. Such effects could have an adverse effect on our financial condition and results of operations.

In terms of opportunities, the regulation of GHG emissions and the introduction of alternative incentives, such as enhanced oil recovery, carbon sequestration, and low carbon fuel standards, could benefit us in a variety of ways. For example, although federal regulation and climate change legislation could reduce the overall demand for the oil and gas that we produce, the relative demand for gas may increase because the burning of gas produces lower levels of emissions than other readily available fossil fuels such as oil and coal. In addition, if renewable resources such as wind or solar power become more prevalent, gas-fired electric plants may provide an alternative backup to maintain consistent electricity supply. Also, if states adopt low-carbon fuel standards, gas may become a more attractive transportation fuel. For the years ended December 31, 2024, and 2023, approximately 37 percent and 40 percent, respectively, of our production on a per BOE basis was gas. Market-based incentives for the capture and storage of carbon dioxide in underground reservoirs, particularly in oil and gas reservoirs, could also benefit us through the potential to obtain GHG emission allowances or offsets from or government incentives for the sequestration of carbon dioxide. For additional information about climate change, air quality, and related environmental matters, refer to Risk Factors – Risks Related to Government Regulations – Legislative and regulatory initiatives and litigation related to global warming and climate change could have an adverse effect on our operations and the demand for oil, gas, and NGLs, and could result in significant litigation, capital, and related expenses and Federal and state regulatory initiatives relating to air quality and greenhouse gas emissions could result in increased costs and additional operating restrictions or delays.

Non-GAAP Financial Measures

Adjusted EBITDAX represents net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, and amortization expense, exploration expense, property abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, 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. 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. Refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report, for definition of and further detail about our Credit Agreement.

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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:

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(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 year ended December 31, 2024, amount excludes certain capital expenditures related to one well deemed non-commercial. For the year ended December 31, 2023, amount excludes certain capital expenditures related to unsuccessful exploration activity for one well that experienced technical issues during the drilling phase. For the year ended December 31, 2022, amount excludes certain capital expenditures related to unsuccessful exploration efforts outside of our core areas of operation.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion includes forward-looking statements. Please refer to the Cautionary Information about Forward-Looking Statements section of this report for important information about these types of statements.

Overview of the Company

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. Our near-term goals include continuing to return value to stockholders through our Stock Repurchase Program and fixed dividend payments, and by focusing on continued operational excellence.

Our asset portfolio is comprised of high-quality assets in the Midland Basin of West Texas and in the Maverick Basin of South Texas that 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.

We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; building and maintaining partnerships with our stakeholders by investing in and connecting with the communities where we live and work; and transparency in reporting our progress in these areas. The Environmental, Social and Governance Committee of our Board of Directors oversees, among other things, the effectiveness of our ESG policies, programs and initiatives, monitors and responds to emerging issues, 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. Please refer to our Definitive Proxy Statement on Schedule 14A for the 2024 annual meeting of stockholders to be filed within 120 days from December 31, 2023, for additional discussion.

We are impacted by global commodity and financial markets that remain subject to heightened levels of uncertainty and volatility. While the rate of inflation in the United States has decreased since the beginning of the year and the average rate of inflation in 2023 was lower than it was in 2022, inflation continues to impact certain aspects of our business. Continued oil production curtailment agreements among OPEC+, instability in the Middle East, economic and trade sanctions associated with the wars between Russia and Ukraine and Israel and Hamas, United States Federal Reserve monetary policy, shipping channel constraints and disruptions, and changes in global oil inventory in storage have driven commodity price volatility, contributed to instances of supply chain disruptions 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. Despite continuing uncertainty, we expect to maximize the value of our high-quality asset base and sustain strong operational performance and financial stability. We remain focused on returning capital to stockholders through cash flow generation.

Outlook

We expect our total 2024 capital program to be between $1.16 billion and $1.20 billion, excluding acquisitions, which we expect to fund with cash flows from operations and cash on hand. We plan to focus our 2024 capital program on highly economic oil development projects in both our Midland Basin and South Texas assets, including the assets we acquired during 2023. We expect to repurchase additional shares of our outstanding common stock through our Stock Repurchase Program during 2024, under which $214.9 million remains available for repurchases through December 31, 2024, as of the filing of this report.

2023 Financial and Operational Highlights

During 2023, we increased the amount of capital we returned to our stockholders, compared with 2022, through repurchases of our outstanding common stock under our Stock Repurchase Program and our fixed quarterly dividend payments, and we expanded our Midland Basin asset position. During the year ended December 31, 2023, we repurchased and subsequently retired 6.9 million shares of our common stock at a cost of $228.0 million, excluding excise taxes, commissions, and fees; we paid dividends of $0.60 per share, an increase from $0.16 per share paid during the year ended December 31, 2022; and we announced a 20 percent increase to our fixed dividend to $0.72 per share annually, to be paid in quarterly increments of $0.18 per share, beginning in the first quarter of 2024. Additionally, we executed strategic acquisitions, exchanges, and leasing activity in the Midland Basin, enabling us to enhance

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our capital efficiency by blocking up acreage and maintaining high working interests. Please refer to Note 3 – Equity and Note 16 – Acquisitions in Part II, Item 8 of this report for additional discussion.

Financial and Operational Results. Average net daily equivalent production for the year ended December 31, 2023, increased five percent to 152.0 MBOE, compared with 145.1 MBOE for 2022 as a result of an increased number of completions in 2023 compared with 2022. The total increase consisted of a 20 percent increase from our South Texas assets, partially offset by a seven percent decrease from our Midland Basin assets. These changes were a result of the timing of well completions, and the timing of capital expenditures during 2022 and 2023.

Realized prices for oil, gas, and NGLs decreased 19 percent, 61 percent, and 35 percent, respectively, for the year ended December 31, 2023, compared with 2022, as a result of decreases in benchmark commodity prices during 2023. Total realized price per BOE decreased 33 percent for the year ended December 31, 2023, compared with 2022, resulting in a 29 percent decrease in oil, gas, and NGL production revenue, which was $2.4 billion for the year ended December 31, 2023, compared with $3.3 billion for 2022. Oil, gas, and NGL production expense of $10.16 per BOE for the year ended December 31, 2023, decreased 13 percent compared with 2022, primarily as a result of decreases in production tax expense per BOE, transportation costs per BOE, and ad valorem tax expense per BOE, partially offset by an increase in LOE per BOE.

We recorded a net derivative gain of $68.2 million for the year ended December 31, 2023, compared to a net derivative loss of $374.0 million for 2022. These amounts include a net derivative settlement gain of $26.9 million for the year ended December 31, 2023, and a net derivative settlement loss of $710.7 million for the year ended December 31, 2022.

Operational activities during the year ended December 31, 2023, resulted in the following:

•Net cash provided by operating activities of $1.6 billion, compared with $1.7 billion for 2022.

•Net income of $817.9 million, or $6.86 per diluted share, compared with net income of $1.1 billion, or $8.96 per diluted share for 2022.

•Adjusted EBITDAX, a non-GAAP financial measure, of $1.7 billion, compared with $1.9 billion for 2022. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to net income and net cash provided by operating activities.

•Total estimated net proved reserves as of December 31, 2023, increased 13 percent from December 31, 2022, to 604.9 MMBOE, of which, 58 percent were liquids (oil and NGLs) and 56 percent were proved developed reserves. The increase primarily consisted of revisions of previous estimates of 113.9 MMBOE related to infill reserves in both our South Texas and Midland Basin programs, partially offset by 55.5 MMBOE of production during 2023. Our proved reserve life index increased to 10.9 years as of December 31, 2023, compared with 10.1 years as of December 31, 2022. Please refer to Reserves in Part I, Items 1 and 2 of this report for additional discussion. The standardized measure of discounted future net cash flows was $6.3 billion as of December 31, 2023, compared with $10.0 billion as of December 31, 2022, which was a decrease of 37 percent year-over-year primarily driven by decreases in benchmark commodity prices during 2023. Please refer to Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion.

Operational Activities. During 2023, successful operational execution resulted in strong well performance in the RockStar and Sweetie Peck areas of our Midland Basin position, and allowed us to maximize capital efficiency. Our South Texas program benefited from continued successful delineation and development of the Austin Chalk formation in addition to sustained strong performance of our Eagle Ford shale wells. Our continued success in both our Midland Basin and South Texas programs is attributable to our top-tier assets and technical teams, and our commitment to geoscience, technology, and innovation.

In our Midland Basin program, we averaged three drilling rigs and one completion crew during 2023. We added a fourth drilling rig at the end of the third quarter to begin drilling on our newly acquired Klondike acreage. We drilled 54 gross (37 net) wells, completed 64 gross (54 net) wells, and acquired additional working interests in five net wells during 2023. Average net daily equivalent production volumes decreased year-over-year by seven percent to 75.4 MBOE. Costs incurred during 2023 totaled $768.1 million, or 62 percent of our total 2023 costs incurred. Drilling and completion activities within our RockStar and Sweetie Peck positions in the Midland Basin were focused primarily on developing the Spraberry and Wolfcamp formations.

In our South Texas program, we averaged two drilling rigs and one completion crew during 2023. We drilled 46 gross (46 net) wells and completed 38 gross (37 net) wells during 2023. Average net daily equivalent production volumes increased year-over-year by 20 percent to 76.7 MBOE. Costs incurred during 2023 totaled $423.5 million, or 34 percent of our total 2023 costs incurred. Drilling and completion activities in South Texas during 2023 were primarily focused on delineating and developing the Austin Chalk formation.

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The table below provides a summary of changes in our drilled but not completed well count and current year drilling, completion, and acquisition activity in our operated programs for the year ended December 31, 2023:

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Note: Amounts may not calculate due to rounding.

(1)    As of December 31, 2022, and 2023, the drilled but not completed well count included nine gross (nine net) wells that were not included in our five-year development plan, eight of which were in the Eagle Ford shale.

(2)    Amount relates to additional working interests acquired in drilled but not completed wells during the year ended December 31, 2023.

Costs Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, are summarized as follows:

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(1)    Please refer to the caption Costs Incurred in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.

Production Results. The table below presents the disaggregation of our net production volumes by product type for each of our assets for the year ended December 31, 2023:

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Note: Amounts may not calculate due to rounding.

Net equivalent production increased five percent for the year ended December 31, 2023, compared with 2022, comprised of a 20 percent increase from our South Texas assets, partially offset by a seven percent decrease from our Midland Basin assets. Please refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between 2023 and 2022 and Between 2022 and 2021 below for additional discussion of production.

Acquisition Activity. During 2023, we acquired approximately 20,000 net acres of oil and gas properties in Dawson and northern Martin counties, Texas. Additionally, in the Midland Basin, we added approximately 9,100 net acres through organic leasing activity, we completed an asset exchange, and we acquired additional working interests in certain wells. Please refer to Note 16 – Acquisitions in Part II, Item 8 of this report for additional discussion.

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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 years ended December 31, 2023, 2022, and 2021:

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(1)    Effective January 1, 2023, 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. For periods prior to 2023, average OPIS price per barrel of NGL, historical or strip, assumed a composite barrel product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline. These product mixes represent the industry standard composite barrel for the respective periods presented and do not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.

Oil prices in 2023 decreased compared with 2022 and increased compared with 2021. Gas and NGL prices in 2023 decreased compared with both 2022 and 2021. Given the uncertainty surrounding global financial markets, production output from OPEC+, global shipping channel constraints and disruptions, instability in the Middle East, economic and trade sanctions associated with the wars between Russia and Ukraine and Israel and Hamas, changes in oil inventory in storage, and the potential impacts of these issues on global commodity and financial markets, 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 further inflation, supply chain disruptions, fluctuations in interest rates, and industry-specific impacts. 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. Our realized prices at local sales points may also be affected by infrastructure capacity in the areas of our operations and beyond.

The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of February 8, 2024, and December 31, 2023:

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

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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. Please refer to Note 7 – Derivative Financial Instruments in Part II, Item 8 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 December 31, 2023, and the preceding three quarters: