Riley Exploration Permian Inc

Overview

Riley Exploration Permian, Inc., together with its wholly-owned subsidiaries, is a growth-oriented, independent oil and natural gas company focused on the acquisition, exploration, development and production of oil, natural gas and NGLs in Texas and New Mexico. The majority of our acreage is located in Yoakum County, Texas and Eddy County, New Mexico.

We focus on horizontal drilling and completions applied to conventional formations in the Permian Basin. Our principal business objective is to deliver long-term shareholder value by development of our existing assets and continuous improvement of our operating capabilities and cost structure by utilizing our extensive technical expertise. We also look for opportunities to add to our drilling inventory through acquisitions that meet our strategic and financial objectives. We believe such growth and corresponding increase in scale can lead to additional operating cost efficiencies.

Management prioritizes corporate sustainability and positioning the Company for success in both the near-term and long-term with initiatives focused on existing business and the transitioning energy landscape. Our strategic 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 returns to our shareholders. We implement this strategy primarily through identification and capture of attractive development opportunities, optimization of our assets and operations and continuous improvement of our cost structure.

In August 2022, the Company's Board of Directors (the "Board") and holders of approximately 75% of our outstanding common stock acting by written consent resolved to amend and restate the Company's Second Amended and Restated Bylaws to change the Company's fiscal year period from October 1st through September 30th each year to January 1st through December 31st each year commencing with the 2022 calendar year. As a result, the Company's 2022 fiscal year was the period from January 1, 2022 to December 31, 2022. However, the fiscal year information for 2021 included here reflects the twelve months ended September 30, 2021.

2023 Acquisition

On April 3, 2023, the Company completed its acquisition of oil and natural gas assets in the Yeso trend of the Permian Basin in Eddy County New Mexico (the "New Mexico Acquisition") from Pecos Oil & Gas, LLC ("Pecos"), a Delaware limited liability company and an affiliate of Cibolo Energy Partners, LLC, for an adjusted purchase price of $325 million, reflective of customary post-closing adjustments. See Note 4 - Acquisitions of Oil and Natural Gas Properties in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of this acquisition.

The Company funded the New Mexico Acquisition through a combination of borrowings under the Company's revolving credit facility ("Credit Facility") and proceeds from the issuance of $200 million of unsecured senior notes ("Senior Notes"). See Note 9 - Long-Term Debt in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our long-term debt.

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. The San Andres Formation is a shelf margin deposit composed of dolomitized carbonates.

Our acreage is primarily located on large contiguous blocks in Yoakum County, Texas, which represents our Champions Field and Eddy County, New Mexico, which represents our Redlake Field acquired in the New Mexico Acquisition. Riley Permian’s acreage in Yoakum County offsets legacy Permian Basin San Andres fields, including the Wasson and Brahaney Fields, which have produced more than 2.1 billion barrels of oil equivalent and 109 million barrels of oil equivalent, respectively, from the San Andres Formation since development in the area began in the 1930s and 1940s. We believe the horizontal San Andres wells we and offset operators have drilled to date have delineated our acreage. In Eddy County, New Mexico, our acreage offsets legacy Permian Basin Abo, Yeso, and San Andres Fields, including the Redlake and Loco Hills Fields, which have produced more than 42 million barrels of oil equivalent and 32 million barrels of oil equivalent, respectively, from the Yeso Formation since development in the area began in 2007 and 2008. Based on the close proximity to these productive fields, combined with the horizontal Yeso wells we and offset operators have drilled to date, we believe we have significantly delineated our acreage.

As of December 31, 2023, we had 44,056 net acres and a total of 402 net producing wells. We operated 96% of our net production for the year ended December 31, 2023 and have an average working interest of 93% in our operated wells. Our average net daily production during the year ended December 31, 2023 was approximately 18,590 Boe/d.

Oil, Natural Gas and NGL Reserves

Summary of Oil, Natural Gas and NGL Reserves

The following table summarizes the Company's estimated proved reserves as of December 31, 2023 and 2022.

(1)Total proved reserves were comprised of 56% and 63%, respectively, of total proved developed producing reserves as of December 31, 2023 and 2022.

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, 2023 and 2022 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 15 - 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 for the year ended December 31, 2023 (in MBoe):

During the year ended December 31, 2023, we acquired 13.6 MMBoe of proved undeveloped reserves, primarily from the New Mexico Acquisition, and incurred costs of approximately $32.5 million to convert 3.4 MMBoe of proved undeveloped reserves to proved developed reserves. Our extensions and discoveries of 14.5 MMBoe were primarily the result of drilling activity during the year, which allowed for offset PUDs. Additionally, we had downward revisions of 5.7 MMBoe. These downward revisions were primarily attributable to the removal of PUDs due to changes in our development schedule, and to a lesser extent increases in estimated operating costs and capital expenditures and decreases in well-level projections in certain undeveloped areas. Consistent with SEC guidelines, PUDs are limited to those locations that are reasonably certain to be developed within five years.

PUDs will be converted from undeveloped to developed with successful development and as the applicable wells begin production. As of December 31, 2023, 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, 2023 were approximately $322.7 million, which we expect to finance 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, 2023, 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 technical person primarily responsible for overseeing the preparation of the estimates is our Reservoir Engineering Manager. Our Reservoir Engineering Manager has over 15 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 of the company 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, well test data, commodity prices, and operating and development 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 Reservoir Engineering Manager 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, 2023 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 by us during the periods indicated. We do not have any natural gas wells, therefore the information set forth in the table below only pertains to oil wells. 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 for the years ended December 31, 2023 and 2022 and the fiscal year ended September 30, 2021:

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

(2)Excludes an exploratory well suspended as of September 30, 2021 and subsequently expensed in the fourth quarter of 2023.

As of December 31, 2023, we had 8 gross (8 net) wells in the process of drilling or active completions stages.

We operated 96% of our production for the year ended December 31, 2023. 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 all 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, 2023:

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

(2)Undeveloped acreage are 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 a working interest is owned.

(4)A net acre is deemed to exist when the sum of the fractional ownership working interest in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole and fractions thereof.

Approximately 93% of our total net acreage is held by production and 1% is held by obligations. For acreage that is not held by production, 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 net undeveloped acreage, as of December 31, 2023 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.

Based on our current development plans, we expect to maintain substantially all of the acreage that would otherwise expire during 2024 either through drilling and establishing production, making lease extension payments, or lease renewal efforts. Approximately 79% of our net undeveloped acreage for 2024 is currently held by continuous drilling and established production. We intend to extend or renew any lease we plan to develop or are still assessing for development that is set to expire in 2024. Given our currently planned drilling activities, we do not expect the amount of any such lease extension payments to be material. Additionally, our Texas acreage is 100% fee leasehold, while our New Mexico acreage is approximately 50% fee and state leasehold with the remaining 50% 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 Redlake Field. The Company's additional acreage is included in the below table 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, 2023 and 2022 and the fiscal year ended September 30, 2021.

(1)The Company's natural gas and NGL sales are presented net of gathering, processing and transportation fees which can result in negative average prices.

As a result of our drilling and completion activity as well as our New Mexico Acquisition, we increased our average net production from 11,505 Boe/d for the year ended December 31, 2022 to an average net production of 18,590 Boe/d for the year ended December 31, 2023. During the year ended December 31, 2023, our production was approximately 71% oil, 14% natural gas and 15% NGLs.

Productive Wells

As of December 31, 2023, we produced from 517 gross (402 net) total wells, which includes both operated and non-operated wells.

Productive wells consist of producing wells and wells capable of production, including oil 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%, resulting in a net revenue interest generally ranging from 75% to 80%.

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 years ended December 31, 2023 and 2022 one purchaser accounted for 70% and 89%, respectively, of our revenue purchased. For the year ended December 31, 2023, an additional purchaser accounted for 10% or more of our revenues. During the year ended December 31, 2022, no other purchaser accounted for 10% or more of our revenues. The loss of either of these purchasers could materially and adversely affect our revenues in the short-term. Further, based on the current demand for oil and natural gas and the availability of other purchasers, we 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.

Transportation

We consider all gathering and delivery infrastructure in conjunction or ahead of development of an area. We strive to install such infrastructure ahead of first production to mitigate flaring and reduce operating costs. 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. A portion of 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.

We are currently a party to a crude oil pipeline transportation agreement with Stakeholder Midstream Crude Oil Pipeline, LLC ("Stakeholder Midstream"). We believe we benefit from relatively low take-away costs as compared to transportation by truck, which also has the benefits of reducing truck traffic and related emissions. In 2022, the Company amended its gas gathering and processing agreement with Stakeholder Midstream to reflect Stakeholder Midstream's commitment to expand their gathering and processing system with a commitment from the Company to deliver an annual minimum volume to Stakeholder Midstream's gathering system for at least seven years beginning on the in-service date of the expanded plant, which occurred in 2023. While the minimum volume commitment is below our forecasted production, there are financial penalties if the minimum activity levels are not met. We did not incur any such penalties during 2023. The additional capacity from the gas processing plant expansion has resulted in increased natural gas volumes processed and decreased gas flaring for the Company.

Competition

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Some of our competitors possess and employ financial resources substantially greater than ours and some competitors employ more technical personnel. These factors can be particularly important in the areas in which we operate. 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.

Seasonality of Business

Weather conditions affect the demand for, and prices of, oil, natural gas and NGLs. Demand for oil, natural gas and NGLs is typically higher in the fourth and first calendar quarters resulting in higher prices. Due to these 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 statutory provisions regulating the development 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, sourcing and disposal of water used in the drilling and completion process, decommissioning and removal of equipment, and the plugging and abandonment of wells. REPX’s operations are also subject to various conservation laws and regulations. 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 crude oil or natural gas wells, as well as regulations that generally prohibit the venting and regulate the flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. State laws, including those in Texas and New Mexico, govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that REPX can produce from its wells and to limit the number of wells or the locations at which REPX can drill, although REPX can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, Texas and New Mexico impose a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within their jurisdictions.

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 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 Production

The production of oil and natural gas is subject to United States federal and state laws and regulations, 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 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, decommissioning and removal of equipment, and the plugging and abandonment of wells. REPX’s operations are also subject to various conservation laws and regulations. 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. These laws and regulations may limit the amount of oil and natural gas wells REPX can drill. 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 locations at which REPX can drill.

The failure to comply with the rules and regulations of oil and natural gas production and related operations can result in substantial penalties. 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

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 $1,000,000 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 $1,000,000 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 make any such statement 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 intrastate or other non-jurisdictional sales or 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. 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 natural gas purchased or sold at wholesale 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 facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, 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 transmission facilities as non-jurisdictional gathering facilities, 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 a pipeline’s status as a gatherer not subject to regulation by FERC as an interstate transmission company. However, the distinction between FERC-regulated transmission services and gathering services unregulated by FERC 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 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 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 basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services 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 states 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 its 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, 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 may (i) require the acquisition of a permit before drilling or other regulated activity commences; (ii) restrict the types, quantities and concentrations of various substances that can be released into the environment; (iii) govern the sourcing and disposal of produced water used in the drilling and completion process; (iv) 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; (v) require some form of remedial action to clean up, prevent or mitigate pollution from former operations such as plugging abandoned wells, decommissioning and removing abandoned surface equipment, or closing earthen pits; (vi) establish specific safety and health criteria addressing worker protection; (vii) impose substantial liabilities for pollution resulting from operations or failure to comply with regulations, including permitting requirements; (viii) require the installation of costly emission monitoring and/or pollution control equipment; (ix) require the preparation and implementation of oil spill prevention, control, and countermeasure plans and risk management plans; and (x) 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, 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 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, 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 August 26, 2022, EPA announced a proposal to designate as hazardous substances under CERCLA both perfluorooctanoic acid (“PFOA”) and perfluorooctanesulfonic acid (“PFOS”), each of which has 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 the development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, 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 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 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. 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 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 Clean Water Act ("CWA") and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including 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”) may be impacted by the planned activity—for example, construction of drilling pads, access roads, or pipelines. Rulemaking by 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. 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 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, 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. To the extent any litigation or future amendments to the rule expand the scope of the Clean Water Act’s jurisdiction, REPX could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas or in connection with stream crossings and preparation and implementation of oil spill prevention, control, and countermeasure ("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” related to the prevention of oil spills and 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. 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 applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private 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 Oil Pollution Act of 1990 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 reviewed at least every five years.

Pursuant to CWA laws and regulations, REPX may also be required to obtain and maintain approvals or permits for the discharge of wastewater, including produced water, or storm water. 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, injection operations when proximate induced seismicity exceeds certain thresholds. Additionally, legal disputes may arise based on allegations that disposal well operations have caused damage to 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. 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, 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 EPA. On November 20, 2023, 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 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 permits are required under the CWA for disposal of REPX’s flowback and produced water in disposal wells.

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, EPA announced the initiation of a new review of the ozone NAAQS to ensure the standards reflect the most current, relevant science. Implementation of revised NAAQS by Texas and New Mexico 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 components (fugitive emissions). More recently, EPA, in December 2023, announced additional final NSPS OOOO program final rules—referred to as Subparts OOOOb and OOOOc—which, once effective upon publication in the Federal Register, 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. 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 expected legal challenges. Changes in the U.S. presidential administration following the 2024 presidential election could also affect the implementation of the NSPS Subpart OOOOb and OOOOc rules 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, and repair them within 15 days of discovery, and maintain records to demonstrate continuous compliance.

Regulation of GHG Emissions

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has 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 has adopted 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 includes 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 GHG Reporting Rule. EPA’s proposed rule to implement the fee requirements, “Waste Emissions Charge for Petroleum and Natural Gas Systems,” was published on January 26, 2024, with comments due by March 11, 2024. 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, EPA proposed and has since announced final 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 to the recently announced final NSPS Subparts OOOOb and OOOOc rules are likely to follow, and thus, the ultimate scope of these 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.

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 has since proposed but not yet finalized the 2022 Waste Prevention Rule, which was published in the Federal Register on November 30, 2022, with comments due January 30, 2023, and is intended to replace the BLM’s existing venting and flaring requirements in its Notice to Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases: Royalty or Compensation for Oil and Gas Lost (“NTL–4A”). These newly proposed rules could result in increased compliance costs on REPX’s operations on federal and Indian lands.

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 its 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 published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. 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 Indian lands.

Certain governmental reviews have recently been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. 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. More recently, the EPA initiated a study of Oil and Gas Extraction Wastewater Management in 2018 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. The EPA released a draft of the study in May 2019 and sought public input until July 1, 2019. The EPA’s final report was issued in May 2020, which found mixed support from stakeholders regarding additional produced water discharge options. The EPA is still determining what, if any, next steps are appropriate regarding produced water management in light of the report. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA, CWA or other regulatory mechanisms.

Congress has 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. The EPA, however, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the SDWA. The EPA has issued permitting guidance for oil and natural gas hydraulic fracturing activities using diesel fuels. Under the guidance, EPA defined the term “diesel” to include five categories of oils, including some such as kerosene, that are not traditionally considered to be diesel. 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, 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 as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may 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 under the Trump 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. Nevertheless, on January 7, 2021, the Department of the Interior issued a rule which excluded incidental takes from the definition of prohibited activities under the Act. This rule was short-lived, however, and in October 2021, the Department of the Interior 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 underlying property operations are 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. If REPX were to have a portion of its 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 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 for ongoing operations. These permits are generally subject to protest, appeal, or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines, and other operations.

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.

Facilities

Our land-based oil and natural gas processing facilities are typical of those found in the Permian Basin. Our facilities located at well locations or centralized lease locations include SWDs and associated gathering lines, storage tank batteries, oil/gas/water separation equipment and pumping equipment. In addition, we own a substantial majority of the electrical power infrastructure on our acreage position, which includes power distribution lines and equipment.

Human Capital

As of December 31, 2023, we employed 90 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 its 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 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.

Diversity and Inclusion

We believe that diversity of 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.

Community Involvement

The Company is dedicated to being a good neighbor in its operating areas. The Company provides 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 for Riley Permian. The Company maintains a culture of continuous improvement in safety and environmental practices, supports a diverse 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, including without limitation, REP LLC and Riley Permian Operating Company, LLC. 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. 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.