SM Energy Co

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 Outlookin 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.

•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

$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:

(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:

(1) Refer to the caption Costs Incurredin 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, 2024:

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 Trendsand 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:

(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.

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 Riskin Overview of Liquidity and Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.