Riley Exploration Permian, Inc.

Overview

Riley Permian is a growth-oriented, independent oil and natural gas company focused on horizontal drilling of conventional oil-saturated and liquids-rich formations in the Permian Basin that produce long-term cash flows. The majority of our acreage is located in Yoakum County, Texas and Eddy County, New Mexico.

Our strategic business objectives include enhancing the rate of return on our invested capital, generating sustainable free cash flow, maintaining a strong and flexible balance sheet and maximizing our returns to shareholders. We implement this strategy primarily through identification and capture of attractive development opportunities, optimization of our assets and pursuing complementary growth opportunities that increase our scale and meet our strategic and financial objectives.

Acquisitions and Divestitures

On April 3, 2023, the Company completed an acquisition of oil and natural gas properties in the Yeso trend of the Permian Basin in Eddy County, New Mexico ("2023 New Mexico Acquisition") from Pecos Oil & Gas, LLC. This acquisition included approximately 10,600 total contiguous net acres of leasehold, 18 net horizontal wells and 250 net vertical wells, which established our initial position in New Mexico.

On May 7, 2024, the Company completed an acquisition of oil and natural gas properties in the Yeso trend of the Permian Basin in Eddy County, New Mexico ("2024 New Mexico Asset Acquisition"), which added 13,900 contiguous net acres to the Company's existing acreage in Eddy County, New Mexico.

On July 1, 2025, the Company completed the acquisition of 100% of the ownership interests of Silverback Exploration II, LLC and its subsidiaries ("Silverback") which own oil and natural gas assets and operations located primarily in the Yeso trend of the Permian Basin in Eddy County, New Mexico (“Silverback Acquisition”). The acquisition added approximately 40,000 net acres directly adjacent to and overlapping with the Company's existing core acreage primarily in Eddy County, New Mexico.

On November 21, 2025, the Company sold its interest in oil and natural gas properties in Texas outside of the Company's core acreage in the Champions field ("Viking Sale") to an affiliate of Combo Resources, LLC ("Combo"). The properties consisted of six established units in Lee and Fayette Counties, Texas, which were jointly developed by the Company and Combo. In exchange for the Company's interest in these assets, we received and subsequently retired 250,000 shares of the Company's common stock.

On December 3, 2025, the Company sold all of our membership interests in Dovetail Midstream, LLC, a wholly owned subsidiary of the Company that holds certain midstream infrastructure projects in Eddy County, New Mexico, to Targa Northern Delaware LLC ("Targa") for an aggregate cash purchase price of approximately $111 million, subject to customary purchase price adjustments (the “Midstream Sale”). The Midstream Sale also provided for the subsequent sale by the Company of certain compressor station assets for an aggregate cash purchase price of approximately $10 million plus reimbursement of $1.4 million of capital improvements; this second transaction closed on December 24, 2025. The Company also has the right to earn up to an additional $60 million in cash payments contingent upon achieving certain volumetric performance thresholds over a five-year period. As part of the Midstream Sale, the Company amended its long-term gas purchase agreement ("A&R Gas Purchase Agreement") for our New Mexico field with Targa, which includes dedicated acreage and a minimum volume commitment for a significant portion of the Company’s natural gas production in New Mexico, with an initial 15-year term from the in-service date, which is expected to commence before the end of 2026. Currently, we transport all of our crude oil, natural gas and NGLs in New Mexico to a few other purchasers.

See Note 4 - Acquisitions and Divestitures in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of the 2023 New Mexico Acquisition, the 2024 New Mexico Asset Acquisition, the Silverback Acquisition (the "New Mexico Acquisitions"), the Viking Sale and the Midstream Sale.

See Note 15 - Commitments and Contingencies in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a discussion of our commitments and contingencies.

Our Properties

The Permian Basin is an oil and natural gas producing area located in West Texas and the adjoining area of Southeastern New Mexico covering an area approximately 250 miles wide and 300 miles long, and encompasses several sub-basins, including the Delaware Basin, Midland Basin, Central Basin Platform and Northwest Shelf.

Our acreage is primarily located on large contiguous blocks in Yoakum County, Texas, which represents our Champions field and in Eddy County, New Mexico, which represents our Red Lake field acquired in the New Mexico Acquisitions. Our acreage in Yoakum County is adjacent to legacy Permian Basin San Andres fields, including the Wasson and Brahaney fields, where conventional development commenced in the 1930s. Horizontal San Andres wells drilled to date by the Company and offset operators have delineated our acreage in the area. In Eddy County, New Mexico, our acreage is adjacent to legacy Permian Basin Abo, Yeso, and San Andres fields, including the Red Lake and Loco Hills fields, which have been producing from vertical wells since the 1950s and from horizontal development since 2007. Based on the proximity of this acreage to established producing fields and the performance of horizontal Yeso wells drilled by the Company and offset operators, we believe our Eddy County acreage is significantly delineated.

As of December 31, 2025, we had 97,538 net acres and a total of 873 net producing wells. We operated 96% of our net production for the year ended December 31, 2025, and have an average working interest of 85% in our operated wells. Our average net daily production during the year ended December 31, 2025, was approximately 29,205 Boe/d.

Facilities

Our land-based oil and natural gas facilities are typical of those found in the Permian Basin. Our facilities located at well locations or centralized lease locations include SWDs, storage tank batteries, associated gathering lines, oil/gas/water separation equipment and pumping equipment. We own the majority of our water disposal infrastructure in both Texas and New Mexico and the electrical power infrastructure including power distribution lines and equipment in our Champions field.

Oil, Natural Gas and NGL Reserves

The following table summarizes the Company's estimated proved reserves:

(1)Total proved reserves were comprised of 59%, 62% and 56% respectively, of total proved developed producing reserves as of December 31, 2025, 2024 and 2023.

Estimates of reserves were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2025, 2024 and 2023 in accordance with SEC guidelines. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties, all of which are located within the continental United States. See "Item 1A. Risk Factors" for a discussion of risks and uncertainties associated with our estimates of proved reserves and related factors, and see Note 17 - Supplemental Oil and Gas Information in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our reserve estimates and pricing.

Proved Undeveloped Reserves (PUDs)

The following table summarizes changes in the Company's estimated PUDs (in MBoe):

PUDs increased by a net 13.7 MMBoe for the year-ended December 31, 2025, as compared to the year-ended December 31, 2024. PUDs increased by 23.0 MMBoe due to extensions and discoveries, due primarily from drilling activity during the year, which allowed for the booking of adjacent PUDs for locations that were previously classified as unproved reserves or not at all. PUDs also increased by 3.3 MMBoe from acquired reserves obtained in the Silverback Acquisition, partially offset by a divestiture due to our Viking Sale of 0.4 MMBoe, a net 2.9 MMBoe increase.

PUDs decreased by 10.8 MMBoe due to conversions, and we incurred approximately $56 million to convert these 10.8 MMBoe of PUDs to proved developed producing ("PDP") reserves. The Company had downward revisions to PUDs of 1.3 MMBoe, which included 3.8 MMBoe of negative revisions partially offset by 2.5 MMBoe of positive revisions. Our negative revisions were primarily attributable to 2.9 MMBoe of development plan changes which resulted in the removal of PUDs from our 5-year forecast, 0.7 MMBoe due to lower commodity prices and 0.2 MMBoe due to ownership interest changes. Consistent with SEC guidelines, PUDs are limited to those locations that are reasonably certain to be developed within five years. Positive revisions were primarily attributable to increased type curve forecasts of natural gas and NGLs sales volumes of 2.3 MMBoe based on improved well performance in addition to decreases in operating expenses that caused positive revisions of 0.2 MMBoe.

PUDs will be converted from undeveloped to developed with successful development and as the applicable wells begin production. As of December 31, 2025, all of the Company's proved undeveloped reserves are planned to be developed within five years from the date they were initially recorded. Estimated costs relating to the future development of the Company's proved undeveloped reserves at December 31, 2025, were approximately $285 million, which we expect to fund through cash flow from operations, borrowings under our Credit Facility and other sources of capital.

Evaluation and Review of Reserves

Our reserve estimates as of December 31, 2025, which we refer to as the Reserve Report, were prepared based on a report by Ryder Scott Company L.P. ("Ryder Scott"), our independent petroleum consulting firm. The Company's technical person primarily responsible for overseeing the preparation of our reserve estimates is our Senior Manager of Corporate Reserves. Our Senior Manager of Corporate Reserves has over 18 years of industry experience, a degree in petroleum engineering, and is a registered professional engineer. Within Ryder Scott, the primary technical person responsible for preparing the estimates set forth in the Reserve Report is Mr. Scott James Wilson, a licensed professional engineer in the states of Alaska, Colorado, Texas, and Wyoming. Mr. Wilson has been a practicing petroleum engineering consultant at Ryder Scott since 2000 and is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers in ongoing reservoir evaluations studies worldwide. Before joining Ryder Scott, Mr. Wilson served in a number of engineering positions with Atlantic Richfield Company. He earned a Bachelor of Science degree in petroleum engineering from the Colorado School of Mines in 1983 and an MBA in Finance from the University of Colorado in 1985, graduating from both with high honors. Mr. Wilson meets or 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 reserves definitions and guidelines. Ryder Scott does not own an interest in any of the Company's properties, nor is it employed by us on a contingent basis.

Internal Controls

We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate the Company's reserves. Our internal technical team members meet with our independent reserve engineers periodically during the period covered by the Reserve Report to discuss the assumptions and methods used in the proved reserve estimation process. The qualifications of the technical persons primarily responsible for overseeing the preparation of the estimates of our reserves are set forth in “Evaluation and Review of Reserves” above. We provided historical information to the independent reserve engineers for the Company's properties, such as ownership interest, oil and natural gas production including type curves, well test data, commodity prices, operating and development costs and GP&T costs.

The preparation of the Company's reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

•review and verification of historical production data, which data is based on actual production as reported by the Company;

•communicating, collaborating, and analyzing with technical personnel in the Company's Operating and Business departments;

•preparation of reserve estimates by the Company's Senior Manager of Corporate Reserves or under her direct supervision;

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

•confirming completeness of reserve estimates for all properties owned and verification of the use of the proper working and net revenue interests; and

•no employee's compensation is tied to the amount of reserves booked.

Estimation of Proved Reserves

Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2025, were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (1) production performance-based methods; (2) material balance-based methods; (3) volumetric-based methods; and (4) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for our properties, due to the mature nature of the properties targeted for development and an abundance of subsurface control data.

To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, historical well cost and operating expense data.

Drilling, Acreage, and Development Activities

Drilling Results

The following table sets forth information with respect to the number of total gross and net oil wells completed during the periods indicated. All wells drilled are classified as oil wells (with associated natural gas and NGLs); we did not drill any wells classified as natural gas wells during the periods presented. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return. The following table presents our development and exploratory drilling results:

(1)Net wells are gross wells multiplied by our fractional working interest.

As of December 31, 2025, we had 11 gross (11.0 net) wells in the process of drilling or active completions stages.

We operated 96% of our production for the year ended December 31, 2025. As operator, we design and manage the development of our wells and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide the majority of the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

Acreage Statistics

The following table sets forth our gross and net acres of developed and undeveloped leasehold as of December 31, 2025:

(1)Developed acreage is acres spaced or assigned to productive wells.

(2)Undeveloped acreage is acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves.

(3)The number of gross acres is the total number of acres in which we owned a working interest.

(4)A net acre is the sum of fractional working interest we owned in gross acres.

Approximately 96% of our total net acreage is held by production or company owned minerals, and 0.15% is held by obligations. For acreage that is not held by production or company owned minerals, unless production is established within the spacing units covering the remaining acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates, the leases will expire in accordance with their respective terms. Substantially all of the leases governing our acreage have continuous development clauses that permit us to continue to hold the acreage under such leases after the expiration of the primary term if we initiate additional development within 120 to 180 days after the completion of the last well drilled on such lease, without the requirement of a lease extension payment. Thereafter, the lease is held with additional development every 120 to 240 days, and generally 180 days, until the entire lease is held by production. None of the Company's horizontal drilling locations associated with proved undeveloped reserves are scheduled for drilling outside of a lease term that is not accounted for with a continuous development schedule or primary term.

The following table sets forth the undeveloped net acreage, as of December 31, 2025, that will expire over the next three years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates:

As of December 31, 2025, approximately 5% of our net leasehold acreage was undeveloped or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves. Additionally, our Texas acreage is 100% fee and state leasehold, while our New Mexico acreage is approximately 62% fee and state leasehold with the remaining 38% consisting of BLM leasehold.

Development Opportunities

The Company has a long history in the Permian Basin. In evaluating and determining drilling locations, we also consider the availability of local infrastructure, drilling support assets, property restrictions and state and local regulations. The drilling locations that we actually drill will depend on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors, and may differ from the locations currently identified.

Oil, Natural Gas and NGL Production, Production Prices and Production Costs

Production and Operating Data

The Company has two fields that represent 15% or more of the Company's total reserves: Champions field and Red Lake field. The Company's additional acreage outside of the Champions and Red Lake fields is included in the table below as Other. The following tables set forth information regarding the Company's production, average realized prices and production costs for the years ended December 31, 2025, 2024 and 2023:

(1)The Company's oil, natural gas and NGL sales are presented net of GP&T costs. These costs, related to natural gas and NGLs, at times exceeded the price we received and resulted in negative average realized prices.

(2)The Company's calculation of the effects of derivative settlements includes gains and losses on the settlement of our commodity derivative contracts. These gains and losses are included under other income (expense) in the Company’s consolidated statements of operations.

(3)During the periods presented, the Company did not have any NGL derivative contracts in place.

As a result of new wells turned to sales and additional production from our Silverback Acquisition, we increased our average net production from 22,546 Boe/d for the year ended December 31, 2024, to an average net production of 29,205 Boe/d for the year ended December 31, 2025. During the year ended December 31, 2025, our production was approximately 60% oil, 18% natural gas and 22% NGLs.

Productive Wells

As of December 31, 2025, we produced from 1,231 gross (873 net) total wells, which included both operated and non-operated wells.

Productive wells consist of producing wells and wells capable of production, including wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which the Company has an interest, operated and non-operated, and net wells are the sum of our fractional working interests owned in gross wells.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.

Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this Annual Report.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 20% to 25%.

Marketing and Customers

We market the majority of the production from properties we operate for both our account and the account of the other working interest owners in these properties.

We sell our production at market prices and to a relatively small number of purchasers, as is customary in the exploration, development and production business. Our purchaser contracts include marketing provisions with our purchasers to market our production. For the year ended December 31, 2025, one purchaser accounted for 60% of our revenue purchased. For the years ended December 31, 2024, and 2023, one purchaser accounted for 70% of our revenue purchased. For the years ended December 31, 2025, 2024 and 2023, an additional purchaser accounted for 30%, 22% and 20%, respectively, of our revenues. Due to the recent acquisition of Stakeholder Midstream, LLC ("Stakeholder") by Targa, and upon commencement of the A&R Gas Purchase Agreement, substantially all of our natural gas and NGL's will be sold to a single purchaser. The loss of either of these purchasers could materially and adversely affect our revenues in the short-term. However, based on the current demand for oil and natural gas and the availability of other purchasers, we currently believe that the loss of any of our purchasers would not have a long-term material adverse effect on our financial condition and results of operations because oil and natural gas are fungible products with well-established markets. Further, the Company has the right to market our oil and natural gas production under these agreements.

Gathering and Transportation

We consider all gathering and delivery infrastructure before and during the development of an area and install such infrastructure ahead of first production. Our oil is collected from the wellhead to our tank batteries and then transported by the purchaser by truck or lease automatic custody transfer or LACT meter and delivered to another pipeline or a refinery. Our natural gas is transported from the wellhead to the purchaser’s meter and pipeline interconnection point. In addition, we move substantially all of our produced water by pipeline connected to company-owned SWDs rather than by truck. Given the amount of disposal water volume, the connection to SWDs helps us reduce our lease operating expenses.

At our Champions field in Texas, we currently transport the majority of our crude oil, natural gas and NGLs through Stakeholder, who was recently acquired by Targa effective January 1, 2026. Transporting crude oil through a pipeline offers the benefits of reducing truck traffic and related emissions, as well as typically lower transportation costs as compared to alternatives for transportation by trucking. Stakeholder also treats and processes the majority of our natural gas and NGLs from our Champions field. The Company currently has a minimum annual volume commitment to Stakeholder, the amount of which is materially below our current and forecasted production. There are financial penalties if the minimum activity levels are not met, and we did not incur any such penalties during 2025, 2024 or 2023. As of December 31, 2025, the Company had less than five years remaining on our contract with Stakeholder.

As part of the Midstream Sale, the Company entered into the A&R Gas Purchase Agreement for our New Mexico field with Targa, which includes dedicated acreage and a minimum volume commitment for a significant portion of the Company’s natural gas production in New Mexico, with an initial 15-year term from the in-service date, which is expected to commence before the end of 2026. Currently, we transport all of our crude oil, natural gas and NGLs in New Mexico to a few other purchasers.

Competition

The oil and natural gas industry is highly competitive, and we compete with numerous companies that have greater resources. Many of these competitors engage not only in exploration and production, but also operate in midstream, refining, and marketing activities across regional, national and global markets. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects, and to evaluate, bid for, and purchase a greater number of properties and prospects than what our financial or technical resources permit. Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to identify, evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Additionally, larger or vertically integrated companies may better manage the impact of existing and evolving federal, state, and local regulations, which would adversely affect our competitive position. The impact of consolidation in the oil and gas industry has led to certain benefits, with reduced competition in some circumstances, including moderating or lower service costs and increased availability of personnel.

Seasonality of Business

Demand for oil typically increases during summer months due to summer travel and following periods of lower demand during spring refinery maintenance season. Demand for natural gas typically increases, at least historically, during winter months for heating purposes, while year-round demand for natural gas occurs for cooling or power generation. Larger purchasers of natural gas utilize storage facilities to manage year-round supply and demand dynamics, which can mitigate seasonal fluctuations. Due to potential seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

Regulation of the Oil and Natural Gas Industry

REPX’s operations are substantially affected by federal, tribal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which REPX owns or operates producing oil and natural gas properties have laws and regulations regulating the development and production of oil and natural gas, including, for example, land use, conservation, well construction, protection of the environment, human health and safety, and costs associated with plugging, abandonment of wells and reclamation costs.

Failure to comply with applicable laws and regulations can result in substantial penalties and delays in development. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although REPX believes it is in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently promulgated, amended or reinterpreted. Therefore, REPX is unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, FERC and the courts. REPX cannot predict when or whether any such proposals may become effective. REPX does not believe that it would be affected by any such action materially different than similarly situated competitors.

Regulation Affecting Drilling, Production and Well Plugging and Abandonment

The production of oil and natural gas is subject to federal, tribal, state and local laws, regulations, codes, ordinances and orders of regulatory bodies under those laws and regulations, governing a wide variety of matters. All of the jurisdictions in which REPX owns or operates producing oil and natural gas properties have statutory and administrative provisions regulating the exploration for and production of oil and natural gas, including, for example, provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the drilling and completion process, the control and permitting of air emissions from well completion and production operations, the management and disposal of wastes and wastewater (including produced water) generated from our operations, decommissioning and removal of equipment, and the plugging and abandonment of wells. REPX’s operations are also subject to various conservation laws and regulations, including in New Mexico and Texas. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from REPX’s wells, negatively affect the economics of production from these wells or limit the number of wells or locations at which REPX can drill.

Notably, we are required by the states in which we operate to post financial assurance in order to provide for abandonment, restoration and remediation of wells, and the amount of that financial assurance varies in the states in which we operate. Public concern over potential environmental impacts, such as groundwater contamination, from “orphan wells”—wells abandoned by an operator presumably no longer in existence that were not properly decommissioned and plugged—has recently been expressed and, in some cases, spurred calls for increasing the required amounts of financial assurance to more accurately reflect the current, actual costs of plugging and abandonment. For example, in October 2025, the New Mexico Oil Conservation Commission (“NMOCC”) conducted a hearing to consider (“NMOCC”) proposed rules that if adopted would substantially increase bonding requirements and introduced higher, per well bonding requirements if a certain percentage of an operator’s wells are considered marginal wells. Whereas a maximum of $250,000 in financial assurance could previously be posted to cover all of an operator’s wells, additional financial assurance in the amount of $150,000 per well would be required for wells considered to be “low producing” or “inactive,” or, for example, if 20 percent or more of an operator’s portfolio of wells are considered marginal or inactive, the $150,000 per well financial assurance requirement applies to all of the operators wells, not just the low producing and inactive wells. In addition, New Mexico proposed adding change-in-operator requirements relating to the demonstration of financial wherewithal for taking on inactive well and plugging and abandonment obligations. The RRC, which regulates oil and gas activities in the state, similarly has inactive well and surface equipment removal requirements that require operators to properly and timely plug and abandon wells and remove associated surface equipment, unless an extension (often requiring additional financial assurance) is granted. Further, fulfillment of these inactive well program requirements is required in connection with a change in operator.

The failure to comply with the rules and regulations of oil and natural gas production and related operations can result in substantial fines, penalties, and/or delays in permitting or other authorizations required for REPX’s operations. REPX’s competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect REPX’s operations.

Regulation of Sales and Transportation of Oil and Other Liquids

Generally, sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Although prices of these energy commodities are currently unregulated, the United States Congress historically has been active in their regulation. REPX cannot predict whether new legislation to regulate oil and NGLs, or the prices charged for these commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on REPX’s operations. Additionally, such sales may be subject to certain state, and potentially federal, reporting requirements.

REPX’s sales of oil are affected by the availability, terms and cost of transportation. Prices received from the sale of crude oil and NGLs may be affected by the cost of transporting those products to market. FERC has jurisdiction under the Interstate Commerce Act (“ICA”), as it existed in 1977, over common carriers engaged in the transportation in interstate commerce by pipeline of crude oil, NGLs and refined petroleum products as part of the continuous movement of the crude oil, NGLs or refined petroleum products in interstate commerce. The ICA requires that pipelines providing jurisdictional movements maintain a tariff on file with FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service be “just and reasonable.” In general, interstate oil pipeline rates must be cost-based, although indexed rates, settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances. Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before FERC.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, REPX believes that the regulation of oil transportation will not affect REPX’s operations in any way that is of material difference from those of REPX’s competitors who are similarly situated.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the NGA, and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

The Energy Policy ("EP") Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act of 2005 provides FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1.0 million per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (ii) to make any untrue statement of material fact or omit to state a material fact necessary to make the statements made not misleading; or (iii) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to non-jurisdictional sales or gathering (such as certain purely intrastate gathering), but does apply to activities of natural gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704, described below, which mandates that certain natural gas market participants report aggregate annual transaction data to aid in market transparency. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, any market participant that engages in wholesale sales or purchases of natural gas that equal or exceed 2,200,000 MMBtus of physical natural gas in the previous calendar year, including natural gas producers, gatherers and marketers, are required to report, on May 1 of each year, aggregate volumes of wholesale physical natural gas purchased or sold in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices to FERC on Form No. 552. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has set forth a general test for determining whether a facility's function is non-jurisdictional or jurisdictional, FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional facilities as non-jurisdictional, or vice versa, and depending on the scope of that decision, REPX’s costs of getting natural gas to point of sale locations may increase. REPX believes that the natural gas pipelines in the gathering systems REPX uses meet the traditional tests FERC has used to establish that a pipeline is not subject to FERC's jurisdiction. However, the distinction between FERC-regulated and non-regulated facilities and pipelines is the subject of ongoing litigation, so the classification and regulation of the gathering facilities REPX owns and uses are subject to change based on future determinations by FERC, the courts and/or Congress. Federal and state regulation of natural gas gathering facilities generally includes various occupational health and safety, environmental and, in some circumstances, nondiscriminatory take requirements. At the state level, natural gas gathering operations may receive even greater regulatory scrutiny, such as being subject to complaint-based rate regulation, and various environmental, safety and operational regulations relating to the design, construction, testing, operation, replacement, removal, remediation and maintenance of gathering facilities.

The price at which REPX sells natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to REPX’s physical sales of these energy commodities, REPX is required to observe anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and under the Commodity Exchange Act (“CEA”), and regulations promulgated thereunder by the Commodity Futures Trading Commission ("CFTC"). The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. Should REPX violate the anti-market manipulation laws and regulations, REPX could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The scope and degree of regulatory oversight and scrutiny of natural gas transportation varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, REPX believes that the regulation of similarly situated intrastate natural gas transportation in any state in which REPX operates and ships natural gas on an intrastate basis will not affect REPX’s operations in any way that is of material difference from those of REPX’s competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that REPX produces, as well as the revenues REPX receives for sales of our natural gas.

Changes in law and to FERC or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and REPX cannot predict what future action FERC or state regulatory bodies will take. REPX does not believe, however, that any regulatory changes will affect REPX in a way that materially differs from the way they will affect other natural gas producers and marketers with which REPX competes.

Regulation of Environmental and Occupational Safety and Health Matters

REPX’s oil and natural gas development operations are subject to numerous stringent federal, tribal, regional, state and local statutes and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to environmental and human health protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations impose numerous obligations applicable to REPX’s operations; for example, they may (i) require the acquisition of a permit before construction, drilling, production or other regulated activity commences; (ii) restrict the types, quantities and concentrations of various substances that can be released into the environment, such as air emissions; (iii) govern the sourcing of water used in the drilling and completion process; (iv) govern the disposal of waste and the reuse or treatment and disposal of produced water generated from oil and gas exploration and production operations; (v) limit or prohibit drilling or other operational activities in certain areas and on certain lands lying within wilderness, wetlands, frontier, threatened or endangered species habitat and other protected areas; (vi) require some form of remedial action to assess clean up, prevent or mitigate pollution from former operations, such as plugging abandoned wells, decommissioning and removing abandoned surface equipment, or closing earthen pits; (vii) establish specific safety and health criteria addressing worker protection, including hazard assessment, hazard communication, and personal protective equipment; (viii) impose substantial liabilities for failure to comply with regulations, including permitting requirements; (ix) require the installation of costly emission monitoring and/or pollution control equipment; (x) require the preparation and implementation of oil spill prevention, control, and countermeasure ("SPCC") plans and risk management plans; and (xi) require the reporting of the types and quantities of various substances that are generated, stored, processed, released, or disposed of in connection with REPX’s properties. In addition, these laws and regulations may restrict the rate of production. Failure to comply with these laws and regulations may result in the assessment of substantial administrative, civil, and criminal penalties, the imposition of corrective action or remediation obligations, as well as possible issuance of injunctions limiting or prohibiting REPX's activities.

The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which REPX’s business operations are subject and for which compliance or noncompliance may have a material adverse impact on REPX’s capital expenditures, results of operations or financial position.

Hazardous Substances and Waste Handling

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of persons that own or owned property where release of a "hazardous substance" occurred or are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and anyone who disposed, transported, or arranged for the transport or disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for certain health studies. In addition, from time to time, the EPA may designate additional materials as hazardous substances under CERCLA, which could result in the listing of new Superfund sites, additional investigation and remediation at current Superfund sites, or in the reopening of Superfund sites that previously received regulatory closure. For example, on May 8, 2024, the EPA finalized a rule, which became effective on July 8, 2024, to designate as hazardous substances under CERCLA both perfluorooctanoic acid (“PFOA”) and perfluorooctanesulfonic acid (“PFOS”), each of which are per- and polyfluoroalkyl substances ("PFAS"), which have been commonly used in a variety of industrial and consumer products. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. REPX generates materials in the course of REPX’s operations that may be regulated as “hazardous substances”. REPX is able to control directly the operation of only those wells with respect to which REPX acts as operator. Notwithstanding REPX’s lack of direct control over wells operated by others, the failure of an operator other than REPX to comply with applicable environmental regulations or the failure of a facility receiving hazardous substances for treatment or disposal to manage the substances properly may, in certain circumstances, be attributed to REPX and result in CERCLA or comparable federal or state liability.

The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA currently specifically excludes drilling fluids, produced waters and other wastes associated with oil and natural gas exploration, development, and production from regulation as hazardous wastes under RCRA Subtitle C. However, this exemption does not apply to all wastes generated during oil and gas operations. Ordinary industrial wastes, such as paint wastes, waste solvents, and laboratory wastes, may still be regulated as hazardous wastes if they exhibit hazardous characteristics or are listed as hazardous under RCRA. These wastes may be regulated by the EPA or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. The consent decree required the EPA to propose a rulemaking no later than March 15, 2019 for revision of the Subtitle D criteria regulations pertaining to oil and natural gas wastes or to sign a determination that revision of the regulations is not necessary. The EPA ultimately concluded that revision of the Subtitle D criteria regulations regarding oil and natural gas wastes was not necessary at that time. But, should future rulemakings or legal challenges result in a loss of the RCRA hazardous-waste exclusion for drilling fluids, produced waters and related wastes, REPX’s costs to manage and dispose of generated wastes could increase, which could have a material adverse effect on REPX’s results of operations and financial position. In addition, in the course of REPX’s operations, REPX generates some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes are listed as hazardous wastes or have hazardous characteristics.

REPX currently owns, leases, or operates numerous properties that have been used for oil and natural gas development and production activities for many years. Although REPX believes that it has utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by REPX, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling, treatment or disposal. In addition, some of REPX’s properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under REPX’s control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under CERCLA, liability is often strict, joint, and several, meaning REPX could be held responsible for the entire cost of cleanup, even if other parties contributed to the contamination or if the contamination occurred before REPX acquired the property. Under such laws, REPX could be required to undertake response or corrective measures, which could include investigation of the nature and extent of contamination, removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging, decommissioning and surface equipment removal, or pit closure operations to prevent future contamination.

Water Discharges

The Federal CWA and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including sediments from well pad, road, and other facility construction activities, produced waters and other oil and natural gas wastes into or near navigable and other regulated waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “USACE"). Whether CWA permitting is required depends upon whether and the extent to which “Waters of the United States” (“WOTUS”), i.e., "jurisdictional waters," may be impacted by the planned activity—for example, construction of drilling pads, access roads, or pipelines. Rulemaking by the EPA and the USACE to define WOTUS has been heavily litigated, resulting in the rule taking effect at times in some states but not others and creating definitions that are more inclusive of certain waters effective in some states and those that are less inclusive effective in other states. The EPA’s and USACE’s WOTUS definition rulemaking published in the Federal Register on January 18, 2023 (the January 2023 Rule) incorporated “relatively permanent” and “significant nexus” standards for determining jurisdiction over adjacent wetlands and additional waters, thereby expanding the types of waters that could be considered WOTUS. However, this WOTUS definition was litigated and eventually amended on August 29, 2023, when the EPA and USACE issued a final rule to conform the WOTUS definition to the U.S. Supreme Court’s May 25, 2023, decision in Sackett v. Environmental Protection Agency, which invalidated parts of the January 2023 Rule. With the August 2023 rulemaking, the EPA and USACE implemented a narrower definition of WOTUS by, for example, removing “interstate wetlands”; redefining “adjacent” to mean “having a continuous surface connection”; and removing the “significant nexus” standard from the provisions regarding tributaries, adjacent wetlands, and intrastate lakes and ponds. The EPA initiated an update to the WOTUS definition in November of 2025 and the proposed rule is under consideration following closure of the public comment period in late 2025. To the extent any litigation or future amendments to the rule expand the scope of the CWA’s jurisdiction, REPX could face increased costs and delays with respect to obtaining permits for dredge and fill activities (e.g., associated with construction) in areas with wetlands or other water features or in connection with stream crossings and preparation and implementation of oil SPCC plans.

The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which amends and augments the oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” for the prevention of oil spills and remediation of damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. In addition, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Under the OPA, owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses a substantial threat of discharge is one type of “responsible party” who is liable. The OPA imposes joint and several liability, without regard to fault, meaning that any responsible party can be held liable for the entire cost of cleanup and damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect REPX’s operations.

SPCC regulations promulgated under the CWA and later amended by the OPA require operators of certain oil and natural gas facilities that store oil in more than threshold quantities, the release of which could reasonably be expected to reach jurisdictional waters, to develop, implement, and maintain an SPCC plan. The SPCC plan must describe oil handling operations, spill prevention practices, discharge or drainage controls, and the personnel, equipment and resources at the facility that are used to prevent oil spills from reaching navigable and other regulated waters or adjoining shorelines, and must be reviewed at least every five years.

Pursuant to CWA laws and regulations and implementation of those laws by states with delegated authority, REPX may also be required to obtain and maintain approvals or permits for the discharge of wastewater, including produced water, or storm water from construction or operational activities. Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances and may impose substantial potential liability for the costs of removal, remediation and damages.

Subsurface Injections

In the course of REPX’s operations, REPX produces water in addition to oil and natural gas. Water that is not recycled may be disposed of in disposal wells, which inject the produced water into non-producing subsurface formations. Underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the U.S. Safe Drinking Water Act (“SDWA”) and analogous state laws. The UIC program requires permits from the EPA or state agency to which the UIC program has been delegated for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect REPX’s ability to dispose of produced water and ultimately increase the cost of REPX’s operations. For example, in response to recent seismic events below ground near disposal wells used for the injection of oil and natural gas-related wastewaters, regulators in some states, including Texas and New Mexico, have imposed more stringent permitting and operating requirements for produced water disposal wells. Both the RRC and NMOCD have policies and rules governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC and NMOCD may deny, modify, suspend or terminate the permit application or existing operating permit for that well. In certain cases operators may be required to reduce, and in some cases even suspend or cease, injection operations when proximate induced seismicity exceeds certain thresholds.

Legal disputes may arise based on allegations that disposal well operations have caused damage to groundwater or neighboring properties or otherwise violated state or federal rules regulating waste disposal. These developments could result in additional regulation, restriction on the use of injection wells by REPX or by commercial disposal well vendors whom REPX may use from time to time to dispose of wastewater, and increased costs of compliance, which could have a material adverse effect on REPX’s capital expenditures and operating costs, financial condition, and results of operations.

In addition, several cases have recently put a spotlight on the issue of whether injection wells may be regulated under the CWA if a direct hydrological connection to a jurisdictional surface water can be established. The split among federal circuit courts of appeals that decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, one of which was granted in February 2019. The EPA has also brought attention to the reach of the CWA’s jurisdiction in such instances by issuing a request for comment in February 2018 regarding the applicability of the CWA permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered “direct,” and whether such discharges would be better addressed through other federal or state programs. In April, 2020, the Supreme Court issued a ruling in the case, County of Maui, Hawaii v. Hawaii Wildlife Fund, holding that discharges into groundwater may be regulated under the CWA if the discharge is the “functional equivalent” of a direct discharge into navigable waters. In April 2019, before the Supreme Court ruling, the EPA issued an Interpretive Statement and additional Request for Comment and, following the ruling, in January 2021, new guidance on the ruling, but that guidance was later rescinded by the EPA. On November 20, 2023, the EPA issued draft guidance outlining the factors that may be considered when evaluating whether discharges through groundwater may be the “functional equivalent” of a direct discharge, and thereby subject to regulation under the CWA National Pollutant Discharge Elimination System Permit Program (which permits point sources to discharge specified amounts of pollutant(s) to waters of the United States under specified conditions, and describes the types of information that should be used in determination). Comments on the draft guidance were due to the agency by December 27, 2023, and to date the EPA has not finalized the guidance. The U.S. Supreme Court’s ruling in County of Maui, Hawaii v. Hawaii Wildlife Fund could result in increased operational costs for REPX if CWA permits are required for disposal of REPX’s flowback and produced water in disposal wells.

The Trump administration has initiated several changes to CWA regulations with the intent of reducing regulatory burdens on oil and gas extraction. Such changes include the WOTUS definition update discussed above, and an announced, but not yet implemented, change to oil and gas extraction effluent guidelines. These changes are still pending and it is uncertain what effects, if any, they will have on REPX’s operations.

Air Emissions

The Federal Clean Air Act (“CAA”) and comparable state laws restrict the emission of air pollutants from many sources, such as tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require REPX to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. Over the next several years, REPX may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard, ("NAAQS") for ozone from 75 to 70 parts per billion and, more recently, on August 21, 2023, the EPA announced the initiation of a new review of the ozone NAAQS to ensure the standards reflect the most current, relevant science. The EPA has also considered designating the Permian Basin as an Ozone Nonattainment Area Implementation of revised NAAQS by Texas and New Mexico or designation by the EPA of the Permian Basin as a Nonattainment Area could result in stricter permitting requirements, delay or prohibit REPX’s ability to obtain required permits and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, beginning in 2012, the EPA adopted new rules under the CAA that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas and, in 2016, oil wells for which well completion operations are conducted (i.e., use reduced emission completions, also known as “green completions”), referred to as New Source Performance Standards ("NSPS") subparts OOOO and OOOOa, respectively. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, pneumatic controllers, storage vessels, and under the NSPS Subpart OOOOa regulations, well-site and compressor station components (fugitive emissions). More recently, the EPA finalized on March 8, 2024, additional final NSPS OOOO program rules—referred to as Subparts OOOOb and OOOOc—which, became effective May 7, 2024, and are expected to have a significant impact on the upstream and midstream oil and gas sectors from an operational cost perspective. The rules impose additional methane and VOC emissions limitations from new, modified, and reconstructed sources, and will regulate existing sources for the first time under the NSPS OOOOc program by requiring states to implement plans that meet or exceed federally established emission reduction guidelines for existing oil and natural gas facilities. However, the EPA under the second Trump administration issued a Final Rule on December 3, 2025, extending certain OOOOb and OOOOc compliance deadlines. Thus, although the bulk of the 2012 and 2016 standards are currently in effect, future implementation and the ultimate scope of VOC and methane emissions for the oil and gas production, transmission, and storage industry segments are uncertain at this time and could be modified further as a result of ongoing rulemakings and legal challenges. See also “—Regulation of GHG Emissions.”

Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase REPX’s costs of development, which costs could be significant. States may also impose more stringent air permitting and air quality requirements than federal requirements. For example, in March 2021, the NMOCD finalized rules to eliminate venting and flaring at new and existing wells and requiring operators to capture at least 98% of natural gas produced from their wells by 2026. In addition, the New Mexico Environment Department adopted a rule in August 2022 that requires oil and natural gas producers in counties that are at risk of non-attainment of federal ozone standards to, among other things, check emission rates and have those calculations certified by a qualified engineer, perform enhanced checks for leaks, repair those leaks within 15 days of discovery, and maintain records to demonstrate continuous compliance.

Regulation of GHG Emissions

Regulation of GHG emissions has been the subject of significant uncertainty at the state and federal level, especially in the past year. In 2009, the EPA made findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment and has since adopted regulations pursuant to the federal CAA that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions are also required to meet “best available control technology” standards that are being established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements could adversely affect REPX’s operations and restrict or delay REPX’s ability to obtain air permits for new or modified sources.

In addition, the EPA implemented its GHG reporting program (“GHGRP”) in 2009, by adopting rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of REPX’s operations. More recently, in August 2022, Congress passed the Inflation Reduction Act (“IRA”), which included requirements to impose fees beginning in 2025 on methane emissions from oil and gas operations that are required to report their GHG emissions under the EPA’s GHGRP. The EPA’s final rule to implement the fee requirements, “Waste Emissions Charge for Petroleum and Natural Gas Systems,” ("WEC Rule") was published on November 18, 2024, and took effect on January 17, 2025. On March 14, 2025, President Trump signed a Joint Resolution of Disapproval that was passed by Congress under the Congressional Review Act, so the 2024 Final WEC Rule is no longer in force or effect. The IRA’s fees requirement has not been repealed, but the EPA is currently unable to promulgate a fee collection rule, creating some uncertainty about the future of fees or taxes on methane emissions, known as Waste Emissions Charges (“WEC”). The One Big Beautiful Bill Act (“OBBBA”) delayed WEC until 2034, and in September of 2025, the EPA proposed a rule dismantling all of its GHGRP other than emissions subject to WEC, and even the limited WEC GHGRP would not be in effect until 2034. The proposed GHGRP reduction rule is currently under review.

Furthermore, as discussed under "Air Emissions," in May 2016, the EPA finalized the NSPS Subpart OOOOa standards for emissions of VOC's and methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. Although limiting VOC emissions has the co-benefit of also limiting methane emissions, and previous iterations of the NSPS Subpart OOOO program limited VOC emissions from these sources, the Subpart OOOOa rules included first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. In addition, the rules impose leak detection and repair requirements intended to address emissions leaks known as “fugitive emissions” from equipment, such as valves, connectors, open ended lines, pressure-relief devices, compressors, instruments and meters. Although much of the initial rules remain intact and effective, the rules have been subject to legal challenges, reconsideration by the EPA, stays, and proposed amendments. More recently, the EPA finalized rules to be codified as NSPS Subparts OOOOb and OOOOc that expand the OOOO regulatory program. For example, notably, the NSPS Subpart OOOOc rules include emissions guidelines to assist states in the development of plans to regulate methane emissions from certain existing sources, which had not previously been regulated under NSPS Subpart OOOO programs. Legal challenges, including by states, to the recently finalized NSPS Subparts OOOOb and OOOOc rules and to the compliance deadline extensions have quickly followed the respective rulemaking actions. Thus, although the bulk of the OOOO and OOOOa rules are currently in effect, the ultimate scope of the OOOO program regulations remains uncertain. Compliance with these rules requires enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks and increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring additional personnel to support these activities or the engagement of third-party contractors to assist with and verify compliance. Further, despite the history of rulemaking concerning GHG emissions engendered by the endangerment finding, on August 1, 2025, the EPA proposed rescinding the endangerment finding, creating additional uncertainty about the scope and extent of GHG regulation in the United States.

The BLM also finalized similar rules regarding the control of methane emissions in November 2016 that apply to oil and natural gas exploration and development activities on federal and Indian lands. The rules sought to minimize venting and flaring of emissions from storage tanks and other equipment and also impose leak detection and repair requirements. However, due to subsequent BLM revisions and multiple legal challenges, the rules were never fully implemented, and in October 2020, the November 2016 rules were struck down by the District Court of Wyoming as the result of one such challenge. In part in response to the IRA requirement for operators to pay royalties on “all gas that is consumed or lost by venting, flaring, or negligent releases through any equipment during upstream operations,” the BLM adopted the Waste Prevention, Production Subject to Royalties, and Resource Conservation Rule (the "Waste Prevention Rule") in April of 2024 and it went into effect on

June 10, 2024. In September of 2024, the United States District Court for the District of North Dakota granted a motion for preliminary injunction filed by the plaintiff states of North Dakota, Texas, Montana, Wyoming, and Utah, which prohibits BLM "from enforcing the 2024 [Waste Prevention] Rule against the [plaintiff states] pending the outcome of this litigation." The litigation is currently being held in abeyance in response to the BLM 's request to do so under the second Trump administration. and, in December of 2025, BLM published an extension to December of 2026 of enforcement deadlines applicable to leak detection and repair, and flares flowing 1,050-6,000 mcf/month. BLM is delaying enforcement because it is considering revisions to these two regulations. The outcome of the BLM's potential revisions to the Waste Prevention Rule and the outcome of the North Dakota litigation could affect the validity and substance of the Waste Prevention Rule in the plaintiff and other states. These newly proposed rules, as may be amended under the Trump administration, could result in increased compliance costs on REPX’s operations on federal and American Indian lands.

At the State level, the New Mexico legislature is currently considering a bill, referred to as the “Clear Horizons Act” or Senate Bill 18, that would require 45% less GHG emissions by 2030, as compared to 2005 levels; 75% less by 2040; and 100% less by 2050 and thereafter. The imposition of substantial GHG emission reduction mandates on oil and gas operations in New Mexico may require significant investment in additional pollution control or gas capture equipment, as well as strain the supply of such equipment and the availability of qualified engineering personnel, which could result in increased capital, employee, and compliance costs for REPX’s operations in New Mexico.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. REPX regularly uses hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but federal agencies have asserted jurisdiction over certain aspects of the process. The EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and publishing permitting guidance in February 2014 addressing the performance of such activities using diesel fuels and defining the term “diesel fuels” to include five categories of oils, including some such as kerosene, that are not traditionally considered to be diesel. The EPA has also taken the following actions: issued final regulations under the federal CAA establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; although final rules have not yet been issued, proposed a rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; and, in June 2016, published an effluent limitation guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In addition, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands, including requirements for chemical disclosure, wellbore integrity, and handling of flowback water. However, following years of litigation, the BLM rescinded the rule in December 2017. BLM’s repeal of the rule was challenged in court, and in March 2020, the Northern District of California issued a ruling in favor of the BLM. This ruling was appealed, but the case has been administratively closed since November 15, 2021. In addition, in May 2022, the U.S. Government Accountability Office released a study on methane emissions from oil and gas development, which included a recommendation that the BLM consider whether to require gas capture plans, including gas capture targets, from operators on federal lands. The reinstatement of the BLM hydraulic fracturing regulations or the promulgation of BLM gas capture regulations may result in additional levels or regulation or complexity that could lead to operational delays and increased operating and compliance costs that could make it more difficult and costly to perform hydraulic fracturing on federal and American Indian lands.

Governmental reviews have historically been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices and could lead to additional regulation. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level. In 2018, the EPA initiated a study of Oil and Gas Extraction Wastewater Management that the agency characterizes as a “holistic look” at how produced water is regulated and managed by the EPA, states, and tribes, and has sought input on these issues from other stakeholders such as academics, non-governmental organizations, and industry. A primary focus of the study is to evaluate whether federal regulations allowing for more discharge options would be beneficial, for example, in addressing areas with concerns over scarcity of water and/or injection options. Following a public input period, the EPA issued a final report in May 2020, which, at the time, found mixed support from stakeholders regarding additional produced water discharge options. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA, CWA or other regulatory mechanisms. For example, the EPA announced in March 2025 that it plans to revise the effluent limitations guidelines for oil and gas wastewater discharges to provide regulatory flexibility and help facilitate beneficial use, and such regulation would likely impose permitting requirements, potentially creating delays in the development of and increased costs of compliance for REPX’s operations. At the state level, New Mexico issued rules in July 2025 governing pilot projects for the reuse of oil and gas wastewater and prohibiting any discharge of that wastewater to surface or groundwater.

Congress has also from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect REPX’s operations.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the RRC issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. In addition, New Mexico and Texas require oil and gas operators to disclose the chemicals utilized in hydraulic fracturing on the Frac Focus website. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.

Compliance with existing related laws has not to date had a material adverse effect on REPX’s operations or financial position, but if new or more stringent federal, tribal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where REPX operates, REPX could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.

Protected Species

The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or that species’ habitat. REPX may conduct operations on oil and natural gas leases in areas where certain species that are listed, or could potentially be listed, as threatened or endangered under the ESA are known to exist. The U.S. Fish and Wildlife Service ("UFWS") may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and the Bald and Golden Eagle Protection Act. In the past, the federal government has issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. While the Department of the Interior ("DOI") under the first Trump presidential administration determined that such “incidental takes” of migratory birds do not violate the Act, this position was overruled by a federal district court in New York in August 2020. The DOI issued a rule which excluded incidental takes from the definition of prohibited activities under the Act, but this rule was short-lived and, in October 2021, the DOI issued a rule to reverse the agency's position on incidental takes. The reversal took effect on December 3, 2021. The identification or designation of previously unprotected species as threatened or endangered in areas where REPX operations are planned or conducted could cause REPX to incur increased costs arising from species protection measures or could result in limitations on REPX’s development activities that could have an adverse impact on REPX’s ability to develop and produce reserves. In November of 2025, the EPA announced four proposed rules aimed at reducing the impacts of the ESA on energy development. The proposed rules are under consideration following closure of the public comment period in late 2025. Meanwhile, uncertainty exists about the ultimate impact of the proposed rules on REPX’s operations. If REPX were to have a portion of our leases designated as critical or suitable habitat, it could also adversely impact the value of REPX’s leases.

OSHA, Emergency Response and Community Right-to-Know, and Risk Management Planning

REPX is subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act, the general duty clause and Risk Management Planning regulations promulgated under section 112(r) of the CAA and comparable state statutes and any implementing regulations require that REPX organizes and/or discloses information about hazardous materials used or produced in REPX’s operations and that this information be provided to employees, state and local governmental authorities and citizens. These laws also require the development of risk management plans for certain facilities to prepare for and prevent accidental releases of extremely hazardous substances and to minimize the consequences of such releases should they occur.

Related Permits and Authorizations

Many environmental laws require REPX to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation, or other oil and natural gas activities, and to maintain these permits and compliance with their requirements, including recordkeeping and reporting, for ongoing operations. These permits are generally subject to protest, appeal, or litigation, which can in certain cases delay or halt projects and cease development, construction, production or operation of wells, pipelines, and other operations.

In addition, oil and natural gas exploration, development and production activities on federal lands, American Indian lands and lands administered by the BLM are subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment. As part of such evaluations, the relevant agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. The NEPA evaluation process can be time-consuming and cause delays in project development. In addition, authorizations under the NEPA also are subject to protest, appeal, or litigation, which can delay or halt projects.

Related Insurance

REPX maintains insurance against some risks associated with aboveground, surface, or underground contamination that may occur as a result of REPX’s exploration and production activities. However, this insurance is at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by REPX. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on REPX’s financial condition and operations.

Human Capital

As of December 31, 2025, we employed 122 people. We operate in a technical industry and depend on a highly skilled workforce in multiple disciplines including engineering, geology, operations, land, information technology, accounting and various other corporate functions. The Company supports our employees in pursuing training opportunities to enhance their professional skills. We are not a party to any collective bargaining agreements with our employees. We understand that employee recruiting, retention and development plays a critical role to our business activities and our ability to achieve our long-term strategy. We believe that diverse backgrounds, experience and perspectives contributes to an innovative workforce and an enriching environment for our employees. We are committed to fostering an inclusive, respectful environment and providing equal opportunity to all qualified persons in our hiring, development, and compensation practices. Our employment decisions are based on merit and qualifications. We believe our relations with our employees to be satisfactory. From time to time, we utilize the services of independent contractors to perform various field and other services.

Compensation and Benefits Program

The Company annually reviews compensation for all employees to adjust compensation for market conditions and attract and retain a highly skilled workforce. In addition to cash and equity compensation, the Company also offers other employee benefits such as life and health (medical, dental and vision) insurance, paid time off, and a 401(k) plan.

Community Involvement

The Company is dedicated to being a good neighbor in our operating areas. The Company provides periodic support through various events, organizations, initiatives and partnerships.

Health, Safety and Environment

Protecting our employees, contractors, the public and the environment is a key focus. The Company maintains a culture of continuous improvement in safety and environmental practices, supports its workforce and inspires teamwork to drive innovation. We identify and mitigate safety risks and integrate a culture of safety by operating according to OSHA standards, processes, and procedures. We also strive to comply with all applicable health, safety and environmental standards, laws and regulations.

Corporate Information

We were formed as a Delaware limited liability company, Riley Exploration – Permian, LLC ("REP LLC"), in 2016. In February 2021, REP LLC consummated a merger pursuant to which REP LLC became a wholly-owned subsidiary of Tengasco, Inc., a Delaware corporation (“Tengasco”), and Tengasco changed its name to Riley Exploration Permian, Inc. (the "Merger"). Our organizational structure includes wholly-owned consolidated subsidiaries through which our operations are conducted and non-wholly-owned joint ventures. Our corporate headquarters are located at 29 E. Reno Avenue, Suite 500, Oklahoma City, Oklahoma 73104, and the phone number at this address is (405) 415-8699.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are available free of charge on our website, www.rileypermian.com, as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. From time to time, our website may include additional information intended for investors, including presentations and press releases. The corporate governance documents available on our website include our Code of Ethics. Information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this Annual Report or any other report that we file with or furnish to the SEC. Reports filed with the SEC are also made available on its website at www.sec.gov.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements, other than statements of historical fact, contained in this Annual Report that include information concerning our possible or assumed future results of operations, business strategies, need for financing, competitive position and potential growth opportunities represent management's beliefs and assumptions based on currently available information and they do not consider the effects of future legislation or regulations. Forward-looking statements include all statements that are not historical facts and can be identified by the use of forward-looking terminology such as the words “believes,” “intends,” “may,” “should,” “anticipates,” “expects,” “could,” “plans,” “estimates,” “projects,” “targets” or comparable terminology or by discussions of strategy or trends. Such statements by their nature involve risks and uncertainties that could significantly affect expected results, and actual future results could differ materially from those described in such forward-looking statements.

These forward-looking statements involve a number of risks and uncertainties that could cause actual results to differ materially from those suggested by the forward-looking statements. Forward-looking statements should therefore be considered in light of various factors, including those set forth in this Annual Report under "Item 1A. Risk Factors," in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and elsewhere in this Annual Report. Because of such risks and uncertainties, we caution you not to place undue reliance on these forward-looking statements. These forward-looking statements speak only as of the date of this Annual Report, or if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities law.

SUMMARY RISK FACTORS

Risks Related to Our Business, Operations, and Strategy

•Recent regulatory restrictions on use of produced water in the Permian Basin could adversely impact our business, results of operations and financial condition.

•Enhanced scrutiny on ESG matters could have an adverse impact on our operations.

•An extended decline in commodity prices may adversely affect our business, financial condition, results of operations, ability to meet our capital expenditure obligations and financial commitments, and the value of our reserves.

•We may be unable to obtain required capital or financing on satisfactory terms in order to fund our exploration and development, which could lead to a decline in our reserves.

•Our exploration and development efforts may not be profitable or achieve our targeted returns.

•Properties we acquire may not produce as projected and may subject us to liabilities.

•Uncertainties could materially alter the occurrence or timing of drilling of our identified drilling locations.

•Reserve estimates depend on many assumptions that may turn out to be inaccurate.

•We are vulnerable to risks associated with operating in one major geographic area.

•We may not be able to access on commercially reasonable terms or otherwise truck transportation, pipelines, gas gathering, transmission, storage and processing facilities to market our oil and natural gas production.

•Our estimated proved undeveloped reserves may not be ultimately developed or produced if their development is costlier or more time consuming than expected.

•We may be unable or fail to successfully integrate acquired assets into our operations and development activities.

•Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline.

•Our undeveloped acreage must be drilled before lease expirations to hold the acreage by production, which could result in a substantial lease renewal cost or loss of our lease and prospective drilling opportunities.

•Funding through capital market transactions may be difficult and expensive due to our small public float, low market capitalization, and limited operating history.

•Covenants in our Credit Facility and Senior Notes may restrict our business and financing activities and our ability to pay dividends or execute stock buybacks.

•We may not be able to generate sufficient cash to service all of our indebtedness.

•Our derivative activities could result in financial losses or could reduce our earnings.

•Our joint ventures expose us to risks which are outside our control.

Risks Related to the Oil and Natural Gas Industry

•Conservation measures, alternative sources of energy and technological advances could reduce demand for oil, natural gas and NGLs.

•Shortages or cost increases related to equipment, supplies or qualified personnel could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

•Negative public perception regarding us and/or our industry could have an adverse effect on our operations.

•General domestic and international economic, market and political conditions, including military conflicts, global economic growth, unpredictability of new tariffs, actions of OPEC+ countries and changes to the current political environment under the new administration;

Risks Related to Public Health, Acts of God, and Cybersecurity

•Our business and operations may be adversely affected by public health crises, such as pandemics and epidemics.

•Power outages or limits and increased energy costs could have a material adverse effect on us.

•Extreme weather conditions could adversely affect our business and operations.

•Our business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.

Risks Related to Legal, Regulatory, and Tax Matters

•Regulations related to environmental and occupational health and safety could adversely affect the cost, manner or feasibility of conducting our operations.

•The decommissioning, plugging, abandonment, and reclamation costs for our facilities could exceed our estimates.

•Increased regulation of our oil and natural gas assets could cause our revenues to decline and operating expenses to increase.

•Regulatory initiatives relating to hydraulic fracturing, regulation of greenhouse gases, water conservation, seismic activity, weatherization, or protection of certain species of wildlife or of sensitive environmental areas could result in increased costs and/or decreased production.

•Increased financial assurance, bonding, or idle well management requirements could require significant capital and reduce liquidity.

•New or increased taxes or fees on oil and natural gas extraction or production or changes in our effective tax rate, could adversely impact us.

Risks Related to Our Common Stock

•The market price of our common stock may be volatile, which could cause the value of an investment in our stock to decline.

•If we fail to continue to meet NYSE American listing requirements, our common stock could be delisted from trading, which would decrease the liquidity of our common stock and ability to raise additional capital.

•Our quarterly cash dividends and stock buybacks, if any, may vary significantly both quarterly and annually.

•Our Board of Directors may modify or revoke our dividend or stock buyback policies at any time at its discretion.

•Available cash for dividends and stock buybacks depends primarily on our cash flow and not solely on our profitability, which may prevent us from paying dividends or executing stock buybacks, even during periods in which we record net income.

Risks Related to the Company

•Our business and operations could be adversely affected if we lose key personnel.

•Our executive officers, directors and principal stockholders have the ability to control or significantly influence all matters submitted to the Company’s stockholders for approval.

•Conflicts of interest could arise in the future between us and certain of our stockholders and their respective affiliates.