SM Energy Co

Reserve estimates are inherently imprecise. Estimates for new discoveries and undeveloped locations are considered more imprecise than reserve estimates for producing oil and gas properties. Accordingly, we expect these estimates to change as new information becomes available. The table below presents the standardized measure of discounted future net cash flows and PV-10. PV-10 is a non-GAAP financial measure that is reconciled to the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure. PV-10 does not include the effects of income taxes on future net revenues. Neither the standardized measure of discounted future net cash flows nor PV-10 represents the fair market value of our oil and gas properties. We and others in the oil and gas industry use PV-10 as a measure to compare the relative size and value of proved reserves held before consideration of tax characteristics specific to individual entities. Refer to the Glossary section of this report for additional information regarding these measures and refer to the reconciliation of the standardized measure of discounted future net cash flows to PV-10 set forth below. The actual quantities and present value of our estimated net proved reserves may be more or less than we have estimated. No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the SEC, since the beginning of the last fiscal year. The table below should be read along with Risk Factors in Part I, Item 1A of this report.

The following table summarizes estimated net proved reserves, the standardized measure of discounted future net cash flows (GAAP), PV-10 (non-GAAP), the prices used in the calculation of net proved reserves estimates, and reserve life index as of December 31, 2024, 2023, and 2022:

(2)The prices used in the calculation of proved reserve estimates reflect the unweighted arithmetic average of the first-day-of-the-month price of each month within the trailing 12-month period in accordance with SEC rules. We then adjust these prices to reflect appropriate quality and location differentials over the period in estimating our net proved reserves.

(3)Refer to the reserve life index term in the Glossary section of this report for a description of how this metric is calculated.

(4)As of December 31, 2024, the reserve life index includes production from our Uinta Basin assets and reflects activity occurring after the closing of the Uinta Basin Acquisition on October 1, 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.

The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to the PV-10 (non-GAAP) of total estimated net proved reserves. Refer to the Glossary section of this report for the definitions of standardized measure of discounted future net cash flows and PV-10.

Proved Undeveloped Reserves

Proved undeveloped reserves include those reserves that are expected to be recovered from future wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of economic producibility when drilled or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. As of December 31, 2024, we did not have any net proved undeveloped reserves that had been on our books in excess of five years, and substantially all of our net proved undeveloped reserves were on acreage that was not expected to expire, or that was expected to be held through renewal, before the targeted completion date.

For proved undeveloped locations that are more than one development spacing area from developed producing locations, we utilized reliable geologic and engineering technology when booking estimated net proved undeveloped reserves. Of the 274.3 MMBOE of total net proved undeveloped reserves as of December 31, 2024, approximately 26.4 MMBOE, 63.0 MMBOE, and 18.7 MMBOE of net proved undeveloped reserves in the Midland Basin, South Texas, and the Uinta Basin, respectively, were offset by more than one development spacing area from the nearest proved developed producing location. We incorporated public and proprietary data from multiple sources to establish geologic continuity of each formation and their producing properties. This included seismic data and interpretations (3-D and micro seismic), open hole log information (both vertically and horizontally collected) and petrophysical analysis of that log data, mud logs, gas sample analysis, measurements of total organic content, thermal maturity, test production, fluid properties, and core data as well as statistical performance data yielding predictable and repeatable reserve estimates within certain analogous areas. These locations were limited to only those areas where both established geologic consistency and sufficient statistical performance data could be demonstrated to provide reasonably certain results.

As of December 31, 2024, estimated net proved undeveloped reserves increased 10.7 MMBOE, or four percent, compared with December 31, 2023. The following table provides a reconciliation of our net proved undeveloped reserves for the year ended December 31, 2024:

Conversions to proved developed. Our 2024 conversion rate was 33 percent and resulted primarily from the development of proved reserves in our Midland Basin program and in our Austin Chalk assets in our South Texas program. During 2024, we incurred $872.9 million on projects with reserves booked as proved undeveloped at the end of 2023, of which $685.6 million was spent on converting net proved undeveloped reserves to proved developed reserves by December 31, 2024. During the fourth quarter of 2024, we incurred $84.4 million on projects with reserves booked as proved undeveloped as of December 31, 2024, that were acquired as part of the Uinta Basin Acquisition. At December 31, 2024, drilled but not completed wells represented 55.9 MMBOE of total estimated net proved undeveloped reserves. We expect to incur $423.1 million of additional capital expenditures in completing these drilled but not completed wells, and we expect all estimated net proved undeveloped reserves to be converted to proved developed reserves within five years from their initial booking as net proved undeveloped reserves.

Purchases of minerals in place. During 2024, we completed the Uinta Basin Acquisition and acquired 62.3 MMBOE of net proved undeveloped reserves in the Uinta Basin. Refer to Note 17 – Acquisitions in Part II Item 8 of this report for additional information and the definition of the Uinta Basin Acquisition.

Revisions of previous estimates. During 2024, revisions of previous estimates totaled 58.0 MMBOE. Positive revisions consisted of 63.1 MMBOE of infill reserves, of which 57.8 MMBOE and 5.3 MMBOE of estimated net proved undeveloped reserves were attributable to our South Texas and Midland Basin programs, respectively. Negative revisions consisted of 2.6 MMBOE related to price revisions as a result of a decrease in gas prices and 2.5 MMBOE that resulted from well performance related to infill development.

Removed for five-year rule. As a result of our testing and delineation efforts in 2024, and the reallocation of capital to include our Uinta Basin assets, we revised certain aspects of our future development plan to focus on maximizing returns and the value of our assets. We removed 30.5 MMBOE of estimated net proved undeveloped reserves that are no longer expected to be developed within the five-year period from initial booking and reclassified these locations to unproved reserve categories, of which 20.1 MMBOE and 10.5 MMBOE related to our South Texas and Midland Basin programs, respectively.

Additions from extensions and discoveries. During 2024, we added 7.8 MMBOE of estimated net proved undeveloped reserves, of which 6.0 MMBOE were in the Midland Basin, and resulted from further development of our assets. The remaining 1.9 MMBOE of additions were in South Texas, and resulted from extensions from our continued success in delineating the Austin Chalk formation.

As of December 31, 2024, estimated future development costs relating to our net proved undeveloped reserves totaled $2.8 billion, and we expect to incur approximately $1.0 billion, $647.3 million, and $590.5 million in 2025, 2026, and 2027, respectively.

Internal Controls Over Proved Reserves Estimates

Our internal controls over the recording of proved reserves are structured to objectively and accurately estimate our reserve quantities and values in compliance with the SEC’s regulations. Our process for managing and monitoring our proved reserves is delegated to our Corporate Engineering group and this year was coordinated by our Corporate Business Development Director, subject to the oversight of our management and the Audit Committee of our Board of Directors (“Audit Committee”), as discussed below. Our Corporate Business Development Director has worked in the energy industry since 1988 and has been employed by the Company since 2000. He holds a Bachelor of Science degree in Petroleum Engineering from Montana Technological University and is a member of the Society of Petroleum Engineers. Technical, geological, and engineering reviews of our assets are performed throughout the year by our staff. Data obtained from these reviews, in conjunction with economic data and our ownership information, is used in making a determination of estimated net proved reserve quantities. Our asset teams’ engineering technical staff do not report directly to our Corporate Business Development Director; they report to either their respective asset technical managers or directly to the regional vice president or senior vice president. This design is intended to promote objective and independent analysis within our asset teams in the proved reserves estimation process.

Third-party Reserves Audit

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services throughout the world since 1937. Ryder Scott performed an independent audit using its own engineering assumptions, but with economic and ownership data we provided. Ryder Scott audits a minimum of 80 percent of our total calculated proved reserve PV-10. In the aggregate, the proved reserve amounts of our audited properties determined by Ryder Scott are required, per our policy, to be within 10 percent of our proved reserve amounts for the total Company, as well as for each respective major asset. The technical person at Ryder Scott primarily responsible for overseeing our reserves audit is a Senior Vice President who received a Bachelor of Science degree in Petroleum Engineering and a Business Foundations Certificate from The University of Texas at Austin in 2002. She is a registered Professional Engineer in the State of Texas and a member of the Society of Petroleum Engineers. The 2024 Ryder Scott audit report is included as Exhibit 99.1.

In addition to a third-party audit, our reserves are reviewed by our management with the Audit Committee. Our management, which includes our President and Chief Executive Officer, Executive Vice President and Chief Financial Officer, and Executive Vice President and Chief Operating Officer, is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. The Audit Committee reviews a summary of the final reserves estimate in conjunction with Ryder Scott’s results and also meets with Ryder Scott representatives, separate from our management, from time to time to discuss processes and findings.