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. Please 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, 2023, 2022, and 2021:

(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)Please refer to the reserve life index term in the Glossary section of this report for information describing how this metric is calculated.

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. Please 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, 2023, 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 263.6 MMBOE of total net proved undeveloped reserves as of December 31, 2023, approximately 36.8 MMBOE of net proved undeveloped reserves in the Midland Basin and 87.3 MMBOE of net proved undeveloped reserves in South Texas 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, 2023, estimated net proved undeveloped reserves increased 44.1 MMBOE, or 20 percent, compared with December 31, 2022. The following table provides a reconciliation of our net proved undeveloped reserves for the year ended December 31, 2023:

(1)Amount may not calculate due to rounding.

Revisions of previous estimates. During 2023, revisions of previous estimates totaled 98.8 MMBOE. Positive revisions consisted of 103.8 MMBOE of infill reserves, of which 60.5 MMBOE and 43.3 MMBOE of estimated net proved undeveloped reserves were attributable to our South Texas and Midland Basin programs, respectively, and 13.3 MMBOE of performance revisions resulted from changes to decline curve estimates based on reservoir engineering analysis. Negative revisions consisted of 14.2 MMBOE that resulted from well performance related to infill development, and price revisions of 4.0 MMBOE that resulted primarily from decreases in benchmark gas and NGL prices.

Conversions to proved developed. Our 2023 conversion rate was 20 percent and primarily resulted from the development of proved reserves in our Midland Basin program and in our Austin Chalk assets in our South Texas program. During 2023, we incurred $740.2 million on projects with reserves booked as proved undeveloped at the end of 2022, of which $515.9 million was spent on converting net proved undeveloped reserves to proved developed reserves by December 31, 2023. At December 31, 2023, drilled but not completed wells represented 41.2 MMBOE of total estimated net proved undeveloped reserves. We expect to incur $212.6 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.

Removed for five-year rule. As a result of our testing and delineation efforts in 2023, we revised certain aspects of our future development plan to focus on maximizing returns and the value of our assets. We removed 30.8 MMBOE of estimated net proved undeveloped reserves and reclassified these locations to unproved reserve categories based on development schedule revisions made partially in response to decreased benchmark gas prices and certain lease obligations. Of the 30.8 MMBOE, 25.8 MMBOE primarily related to our Eagle Ford assets in our South Texas program, and 5.0 MMBOE related to our Midland Basin program.

Additions from extensions and discoveries. During 2023, we added 22.7 MMBOE of estimated net proved undeveloped reserves, of which 21.9 MMBOE were in South Texas, and resulted from extensions from our continued success in delineating the Austin Chalk formation.

As of December 31, 2023, estimated future development costs relating to our net proved undeveloped reserves totaled $2.8 billion, and we expect to incur approximately $860.6 million, $585.6 million, and $555.7 million in 2024, 2025, and 2026, 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 reserves group and is coordinated by our Corporate Engineering Manager, subject to the oversight of our management and the Audit Committee of our Board of Directors (“Audit Committee”), as discussed below. Our Corporate Engineering Manager has worked in the energy industry since 2008 and has been employed by the Company since 2010. He holds a Bachelor of Science degree in Petroleum Engineering from Montana Technological University and is a Registered Professional Petroleum Engineer in the states of Texas, Wyoming, and Montana. He is also 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 proved reserve quantities. Our asset teams’ engineering technical staff do not report directly to our Corporate Engineering Manager; they report to either their respective asset technical managers or directly to the Senior Vice President of Exploration, Development and EHS. 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 2023 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 Senior Vice President of Exploration, Development and EHS, 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.