NYSE: SD

PRIMARY BUSINESS OPERATIONS

Our primary operations are the production, development and acquisition of hydrocarbon resources. The following table presents information concerning our operations as of December 31, 2025.

Estimated Proved Reserves (MMBoe) (1) Daily Production (MBoe/d)(2) Reserves/ Production (Years)(3) Weighted Average Economic Reserve Life (Years)(4) Gross Acreage Net Acreage

Geographic Area

Mid-Continent 69.1 18.5 10.2 35.0 574,599 378,537

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(1) Estimated proved reserves were determined using SEC prices, and do not reflect actual prices received or current market prices. All prices are held constant throughout the lives of the properties. The index prices and the equivalent weighted average wellhead prices used in the reserve reports are shown on page 10 below.

(2) Average daily net production for the year ended December 31, 2025.

(3) Estimated proved reserves as of December 31, 2025 divided by net production for the year ended December 31, 2025.

(4) Average economic reserve life using SEC prices and weighted for reserve volumes at December 31, 2025.

Properties

Mid-Continent

We held interests in 574,599 gross (378,537 net) leasehold acres located primarily in Oklahoma, Kansas, and Texas at December 31, 2025. Associated proved reserves at December 31, 2025 totaled 69.1 MMBoe. Our interests in the Mid-Continent as of December 31, 2025 included 1,446 gross (825 net) producing wells with an average working interest of 57.1%. The interests are largely aggregated across the Mississippian Lime, Meramec and Cherokee formations. The Mississippian Lime formation is an expansive carbonate hydrocarbon system located on the Anadarko Shelf in northern Oklahoma and southern Kansas. The top of this formation is encountered between approximately 4,000 and 7,000 feet and stratigraphically between various formations of Pennsylvanian age and the Devonian-aged Woodford Shale formation. The Mississippian formation is approximately 350 to 650 feet in gross thickness across our lease position and has targeted porosity zone(s) ranging between 20 and 150 feet in thickness. The Meramec Formation is Mississippian in age, lying above the Woodford Shale and below Chester formations. The Meramec is composed of interbedded shales, sands, and carbonates. The top of this target formation ranges in depth from about 5,800 feet at the northern edge of the basin to greater than 14,000 feet toward the interior of the basin. Meramec formation thickness ranges from about 50 feet to over 400 feet. The Woodford Shale is the primary hydrocarbon source for the Meramec. The Cherokee Formation of the Western Anadarko Basin has become a prolific hydrocarbon producer with increased horizontal activity over the last few years. Pennsylvanian in age, the Cherokee overlies the Atoka and is overlain by the Marmaton Group. The Cherokee Formation is comprised of mostly self-sourcing shales with interbedded high porosity sands. Depths of the top of the Cherokee within the Western Anadarko Basin range from approximately 8,500 feet north of the basin to greater than 13,000 feet basinward, with a thickness ranging from 400 feet to greater than 2,500 feet.

Proved Reserves

The portion of a reservoir considered to contain proved reserves includes (i) the portion identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil, natural gas or NGLs on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty.

Existing economic conditions include prices, costs, operating methods and government regulations existing at the time the reserve estimates are made. SEC prices are used to determine proved reserves, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. See further discussion of prices in “Risk Factors” included in Item 1A of this report.

Preparation of Reserves Estimates

Approximately 97.9% of the proved oil, natural gas and NGL reserves disclosed in this report have been independently prepared by Cawley, Gillespie & Associates (“CGA”), a leader of petroleum property analysis for industry and financial institutions. CGA was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CGA, the technical person primarily responsible for preparing the estimates set forth in the CGA letter dated January 20, 2026, filed as an exhibit to this Annual Report on Form 10-K, was Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CGA since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 38 years of practical experience in petroleum engineering, with over 36 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets and exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

The primary technical person responsible for preparing the reserve estimates within the Company is Mr. Eric Allen, the Reservoir Engineering Manager. Mr. Allen graduated from Oklahoma State University with a Bachelor of Science in Chemical Engineering in 2010 and has been practicing petroleum engineering since graduating. In 2016, Mr. Allen graduated from the University of Oklahoma with a Master’s in Business Administration. Mr. Allen has over 16 years of practical experience in petroleum engineering with 11 of those years having been spent in the estimation and evaluation of reserves. Since 2016, Mr. Allen has been a Registered Professional Engineer in the State of Oklahoma (License No. 29209) and is an active member of the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines. In addition to Mr. Allen's preparation of the reserve estimates, those estimates are further reviewed by the executive team and the Audit Committee (the “Audit Committee”) of the Board of Directors of the Company (the “Board”) .

To establish reasonable certainty with respect to our estimated proved reserves, the independent and internal reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used to estimate the Company’s proved reserves include, but are not limited to, production data, historical price and cost information, property ownership, well logs, geologic maps and well tests. This data was reviewed by various levels of management for accuracy before consultation with independent reserve engineers. This consultation included review of properties, assumptions and available data. Internal reserve estimates were compared to those prepared by independent reserve engineers to test the estimates and conclusions before the reserves were included in this report. The accuracy of the reserve estimates is dependent on many factors, including the following:

•the quality and quantity of available data and the engineering and geological interpretation of that data;

•estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;

•the accuracy of economic assumptions; and

•the judgment of the personnel preparing the estimates.

The Reservoir Engineering Manager serves as the primary technical professional providing oversight of our reserve estimate. CGA and the Reservoir Engineering Manager monitor well performance and make reserve estimate adjustments as necessary to ensure the most current information is reflected.

We encourage ongoing professional education for our engineers and analysts on new technologies and industry advancements as well as refresher training on basic skill sets.

In order to ensure the reliability of reserves estimates, SandRidge has a comprehensive SEC-compliant internal controls framework and set of policies to determine, estimate and report proved reserves including:

•confirming that we include reserves estimates for all properties owned and that they are based upon proper working and net revenue interests;

•ensuring the information provided by other departments within the Company such as Accounting is accurate and complete;

•communicating, collaborating, and analyzing with technical personnel;

•comparing and reconciling the internally generated reserves estimates to those prepared by third parties;

•utilizing experienced reservoir engineers or those under their direct supervision to prepare reserve estimates; and

•ensuring compensation for the reserve engineers is not tied to the amount of reserves recorded.

Key reserve information is reviewed quarterly and approved at least annually by the Company’s Chief Executive Officer and Chief Financial Officer.

SandRidge’s reserve engineers and the Reservoir Engineering Manager work closely with independent petroleum consultants at each fiscal year end to ensure the integrity, accuracy and timeliness of annual independent reserves estimates. These independently developed reserve estimates are presented to the Audit Committee. In addition to reviewing the independently developed reserve reports, the Audit Committee also periodically meets with the independent petroleum consultants that prepare estimates of proved reserves.

The percentage of total proved reserves prepared by the independent petroleum consultants is shown in the

table below.

Year Ended December 31,

2025 2024

Cawley, Gillespie & Associates, Inc. 97.9 % 97.5 %

Total 97.9 % 97.5 %

The remaining 2.1% and 2.5% of estimated proved reserves as of December 31, 2025 and 2024 were based on internally prepared estimates.

A copy of the report issued by our independent reserve consultant with respect to our oil, natural gas and NGL reserves as of December 31, 2025 is filed with this report as Exhibit 99.1. Cawley, Gillespie & Associates prepared reserves for our Mid-Continent properties located in Kansas, Oklahoma, and Texas as of December 31, 2025.

Reporting of Natural Gas Liquids

NGLs are recovered through further processing of a portion of our natural gas production stream. At December 31, 2025, NGLs comprised approximately 35.4% of total proved reserves on a barrel equivalent basis and represented volumes to be produced from properties where we have contracts in place for the extraction and sale of NGLs. NGLs are products sold by the gallon. In reporting proved reserves and production of NGLs, we have included production and reserves in barrels based on a conversion rate of 42 gallons per barrel. The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale. The amount of NGLs extracted from produced gas can vary with individual component prices and we have limited direct control over the extent to which NGLs are extracted from our natural gas, particularly light-end components such as ethane. All production information related to natural gas is reported net of the effect of any reduction in natural gas volumes resulting from the processing and extraction of NGLs.

Reserve Quantities, PV-10 and Standardized Measure

The following estimates of proved oil, natural gas and NGL reserves are based on reserve reports as of December 31, 2025 and 2024, of which approximately 97.9% and 97.5%, respectively, were prepared by independent reserve engineers.

See “Critical Accounting Policies and Estimates” in Item 7 of this report for further discussion of uncertainties inherent to the reserves estimates.

Year Ended December 31,

2025 2024

Estimated Proved Reserves (1)

Developed

Oil (MMBbls) 8.2 7.9

Natural gas (Bcf) 184.1 183.6

NGL (MMBbls) 21.4 18.5

Total proved developed (MMBoe) 60.3 57.0

Undeveloped

Oil (MMBbls) 2.8 1.9

Natural gas (Bcf) 18.2 12.3

NGL (MMBbls) 3.0 2.2

Total proved undeveloped (MMBoe) 8.8 6.1

Total Proved

Oil (MMBbls) 11.0 9.7

Natural gas (Bcf) 202.3 195.9

NGL (MMBbls) 24.5 20.7

Total proved (MMBoe) 69.1 63.1

Standardized Measure of Discounted Net Cash Flows (in millions) (2) $439.6 $362.7

PV-10 (in millions) (3) $439.6 $362.7

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(1) Estimated proved reserves, PV-10 and Standardized Measure were determined using SEC prices, and do not reflect actual prices received or current market prices. All prices are held constant throughout the lives of the properties.

(2) Standardized Measure differs from PV-10 as standardized measure includes the effect of future income taxes.

(3) PV-10 is a non-GAAP financial measure. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of our oil and natural gas properties. PV-10 is used by the industry and by management as a reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities.

The index prices and the equivalent weighted average wellhead prices used in the reserve reports are shown in the table

below:

Index prices (a) Weighted average wellhead prices (b)

Oil (per Bbl) Natural gas (per MMBtu) Oil (per Bbl) NGL (per Bbl) Natural gas (per Mcf)

December 31, 2025 $ 65.34 $ 3.39 $ 64.15 $ 17.13 $ 2.07

December 31, 2024 $ 75.48 $ 2.13 $ 74.04 $ 19.40 $ 1.02

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(a) Index prices are based on average WTI Cushing spot prices for oil and average Henry Hub spot market prices for natural gas. These are SEC prices calculated by using trailing 12 month averages from the first trading day close of each calendar month.

(b) Average adjusted volume-weighted wellhead product prices reflect adjustments for transportation, quality, gravity, regional price differentials and exclude any impact of derivatives.

The following table provides a reconciliation of our PV-10 to Standardized Measure:

Year Ended December 31,

2025 2024

(In thousands)

PV-10 $ 439,568 $ 362,696

Present value of future income tax discounted at 10% — —

Standardized Measure of Discounted Net Cash Flows $ 439,568 $ 362,696

Proved Reserves - Proved reserves increased from 63.1 MMBoe at December 31, 2024 to 69.1 MMBoe at December 31, 2025, due to extensions of 7.3 MMBoe, purchases of 1.7 MMBoe, positive net revisions of 3.2 MMBoe due to an increase in year-end SEC natural gas pricing and price realizations and 4.5 MMBoe associated with other commercial improvements. These were partially offset by a decrease in SEC oil pricing, 6.8 MMBoe from the Company’s production during 2025, and 3.9 MMBoe attributable to performance, well shut-ins and other revisions.

Proved Developed Reserves - Proved developed reserves increased from 57.0 MMBoe at December 31, 2024 to 60.3 MMBoe at December 31, 2025, primarily due to positive revisions of 3.2 MMBoe due to an increase in year-end SEC natural gas pricing and price realizations, extensions of 0.8 MMBoe, 4.7 MMBoe of proved undeveloped ("PUD") converted to proved developed ("PDP") reserves in 2025 under our Cherokee play development program and 4.5 MMBoe associated with other commercial improvements. These were partially offset by negative revisions including 6.8 MMBoe from the Company’s production during 2025, and 3.1 MMBoe attributable to the decrease in SEC oil pricing, well shut-ins and other revisions.

Proved Undeveloped Reserves - Proved undeveloped reserves increased from 6.1 MMBoe at December 31, 2024 to 8.8 MMBoe at December 31, 2025 due to extensions of 6.5 MMBoe and purchases of 1.7 MMBoe. There were PUD to PDP conversions of 4.7 MMBoe from five operated and four non-operated wells drilled and turned online in 2025. The company invested $43.7 million to convert these reserves to PDP. Total increase to proved undeveloped reserves were also partially offset by 0.8 MMBoe attributable to other negative revisions including the decrease in SEC oil pricing.

For additional information regarding changes in proved reserves during each of the three years ended December 31, 2025, 2024 and 2023 see “Note 20—Supplemental Information on Oil and Natural Gas Producing Activities” to the accompanying consolidated financial statements in Item 8 of this report.

Production and Price History

The following table includes information regarding our net oil, natural gas and NGL production and certain price and cost information for each of the periods indicated.

Year Ended December 31,

2025 2024 2023

Production data (in thousands)

Oil (MBbls) 1,214 918 1,047

Natural gas (MMcf) 19,802 19,488 20,403

NGL (MBbls) 2,254 1,889 1,705

Total volumes (MBoe) 6,768 6,056 6,152

Average daily total volumes (MBoe/d) 18.5 16.5 16.9

Average prices—as reported (1)

Oil (per Bbl) $ 63.64 $ 74.31 $ 74.69

Natural gas (per Mcf) $ 2.10 $ 1.10 $ 1.71

NGL (per Bbl) $ 16.64 $ 18.87 $ 20.83

Total (per Boe) $ 23.10 $ 20.69 $ 24.16

Expenses per Boe

Production costs (2) $ 5.35 $ 6.61 $ 6.80

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(1)Prices represent actual average prices for the periods presented and do not include effects of derivative transactions.

(2)Represents production costs per Boe excluding production and ad valorem taxes.

Productive Wells

The following table presents the number of productive wells in which we owned a working interest at December 31, 2025. We operate the majority of all wells in which we owned a working interest at December 31, 2025 and 2024. Productive wells consist of wells that are currently producing hydrocarbons. Gross wells are the total number of producing wells in which we have a working interest and net wells are the sum of the fractional working interests owned in gross wells.

Oil Natural Gas Total

Gross Net Gross Net Gross Net

Geographic Area

Mid-Continent 1,142 635 304 190 1,446 825

Drilling Activity

During the year ended December 31, 2025, the Company operated one drilling rig and drilled seven operated wells and completed six wells with one well drilling and another well awaiting completion as of December 31, 2025. Additionally, four non-operated wells were drilled and completed during 2025. During the year ended December 31, 2024, there were no operated wells drilled, three operated wells and one non-operated well completed with zero wells awaiting completion at year end 2024.

Developed and Undeveloped Acreage

The following table presents information regarding our developed and undeveloped acreage at December 31, 2025.

Developed Acreage Undeveloped Acreage

Gross Net Gross Net

Geographic Area

Mid-Continent 491,197 337,623 83,402 40,914

40% of leases that expire included in the net undeveloped acreage above will expire at the end of their respective primary terms. To prevent expiration, we may exercise our contractual rights to extend the terms of leases we value or may establish production from the leasehold acreage prior to expiration, which would keep the lease from expiring until production has ceased.

As of December 31, 2025, the gross and net acres subject to leases in the undeveloped acreage above are set to expire as follows:

Acres Expiring

Gross Net

Twelve Months Ending

December 31, 2026 2,579 1,727

December 31, 2027 16,062 12,915

December 31, 2028 5,198 1,857

Total (1) 23,839 16,499

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(1)The Company has 59,563 gross (24,415 net) undeveloped acres not subject to expiration.

Marketing

We sell our oil, natural gas and NGLs to a variety of customers, including oil and natural gas companies and trading and energy marketing companies. We had three purchasers that each individually accounted for more than 10% of our total revenue during the year ended December 31, 2025. See “Note 1—Summary of Significant Accounting Policies” to the accompanying consolidated financial statements in Item 8 of this report for additional information on our major customers. The number of available purchasers and markets in the areas where we sell our production reduces the risk that loss of a single downstream customer would materially affect our sales. We do not have any material commitments to deliver fixed and determinable quantities of oil and natural gas in the future under existing sales contracts or sales agreements.

Title to Properties

As is customary in the oil and natural gas industry, we conduct a preliminary review of the title to our properties. Prior to commencing drilling operations on our properties, we conduct a thorough title examination and perform curative work with respect to significant defects, typically at our expense. In addition, prior to completing an acquisition of producing oil and natural gas assets, we perform title reviews on the most significant leases and depending on the materiality of properties, may obtain a drilling title opinion or review previously obtained title opinions. To date, we have obtained drilling title opinions on substantially all of our producing properties and believe that we have good and defensible title to our producing properties. Our oil and natural gas properties are subject to customary royalty and other interests, and liens for current taxes and other burdens, which we believe does not materially interfere with the use of, or affect the carrying value of the properties.

COMPETITION

We compete with other oil and natural gas companies for leases, equipment, personnel and markets for the sale of oil, natural gas and NGLs. We believe our leasehold acreage position, geographic concentration of operations and technical and operational capabilities enable us to compete with other oil and gas development and production companies in the areas in which we operate. However, the oil and natural gas industry is intensely competitive. See “