UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM			10-K


x			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, ~~2024~~2025


o			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 001-15555

Riley Exploration Permian, Inc.

(Exact name of registrant as specified in its charter)


Delaware						87-0267438
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

29 E. Reno Avenue, Suite 500 Oklahoma City, Oklahoma						73104
(Address of Principal Executive Offices)						(Zip Code)

Registrant's telephone number, including area code: (405) 415-8699

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common stock, par value $0.001	REPX	NYSE American

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer x Non-accelerated filer o Smaller reporting company xo Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. o

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.1D-01(b). o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 USC. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. x

Aggregate market value of the voting common equity held by non-affiliates of registrant as of June 30, ~~2024~~2025 was approximately $~~254~~258.57 million.

The total number of shares of common stock, par value $0.001 per share, outstanding as of ~~February~~March 282, ~~2025~~2026 was 21,~~505~~567,~~338~~428.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of this Annual Report on Form 10-K ("Annual Report"), to the extent not set forth herein, is incorporated herein by reference from the registrant's definitive proxy statement relating to the Annual Meeting of Stockholders to be held in ~~2025~~2026, which definitive proxy statement shall be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report relates.

RILEY EXPLORATION PERMIAN, INC.
ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2024
ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2025
TABLE OF CONTENTS
		Page
Part I
Items 1 and 2.	Business and Properties	86
Item 1A.	Risk Factors	2728
Item 1B.	Unresolved Staff Comments	5657
Item 1C.	Cybersecurity	5657
Item 3.	Legal Proceedings	5859
Item 4.	Mine Safety Disclosures	5859
Part II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	5960
Item 6.	Selected Financial Data	6061
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	6061
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	7274
Item 8.	Financial Statements and Supplementary Data	7275
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	7275
Item 9A.	Controls and Procedures	7275
Item 9B.	Other Information	7578
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	7578
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	7679
Item 11.	Executive Compensation	7679
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	7679
Item 13.	Certain Relationships and Related Transactions, and Director Independence	7679
Item 14.	Principal Accountant Fees and Services	7679
Part IV
Item 15.	Exhibits and Financial Statements Schedules	7780
Item 16.	Form 10-K Summary	8083
Signatures		8184

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DEFINITIONS

As used in this Annual Report, unless otherwise noted or the context otherwise requires, we refer to Riley Exploration Permian, Inc., together with its subsidiaries, as "Riley Permian," "REPX," "the Company," "Registrant," "we," "our," or "us." In addition, this Annual Report includes certain terms commonly used in the oil and natural gas industry, and the following are abbreviations and definitions of certain terms used within this Annual Report on Form 10-K:

Measurements.
Bbl			One barrel or 42 U.S. gallons liquid volume of oil or other liquid hydrocarbons
Boe			One stock tank barrel equivalent of oil, calculated by converting gas volumes to equivalent oil barrels at a ratio of 6 thousand cubic feet of gas to 1 barrel of oil and by converting NGL volumes to equivalent oil barrels at a ratio of 1 barrel of NGL to 1 barrel of oil
Boe/d			Stock tank barrel equivalent of oil per day
Btu			British thermal unit. One British thermal unit is the amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit
MBbl			One thousand barrels of oil or other liquid hydrocarbons
MBoe			One thousand Boe
MBoe/d			One thousand Boe per day
Mcf			One thousand cubic feet of gas
MMBoe			One million Boe
MMBtu			One million British thermal units
MMcf			One million cubic feet of gas
Abbreviations.
ARO			Asset Retirement Obligation
BLM			Bureau of Land Management
Credit Facility			A credit agreement among Riley Exploration - Permian, LLC, as borrower, and Riley Exploration Permian, Inc, as parent guarantor, with Truist Bank and certain lenders party thereto, as amended
CO2			Carbon Dioxide
CWA			Clean Water Act
DD&A			Depreciation, depletion and amortization
EOR			Enhanced Oil Recovery
EPA			Environmental Protection Agency
ERCOT			Electric Reliability Council of Texas
ESG			Environmental, social, and governance
FERC			Federal Energy Regulatory Commission
GHG			Greenhouse Gas
IRS			Internal Revenue Service
GP&T costs			Gathering, processing and transportation costs
NGA			Natural Gas Act of 1938
NGL			Natural gas liquids
NGPA			Natural Gas Policy Act of 1978
NMOCD			New Mexico Oil Conservation Division
NYMEX			New York Mercantile Exchange
NYSE			New York Stock Exchange
Oil			Crude oil and condensate
OPEC+			Organization of the Petroleum Exporting Countries ("OPEC") members and non-OPEC allies
RRC			Railroad Commission of Texas
SEC			Securities and Exchange Commission
Senior Notes			The Company's unsecured 10.5% senior notes due April 2028
SWD			Saltwater Disposal Well
WTI			West Texas Intermediate

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Terms and Definitions.
Developed oil and natural gas reserves			Developed oil and natural gas reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Development project			A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
Development well			A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential			An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Economically producible			The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and natural gas producing activities. The terminal point is generally regarded as the outlet valve on the lease or field storage tank.

Exploratory well			A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.

Operator			The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
Play			A geographic area with hydrocarbon potential.

Proved oil and natural gas reserves			Proved oil and natural gas 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 estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

Proved undeveloped reserves			Proved undeveloped reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
PV-10			The present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of the applicable company on a comparable basis to other companies and from period to period.

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Reserves			Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reserve additions			Changes in proved reserves due to revisions of previous estimates, extensions, discoveries, improved recovery, and other additions and purchases of reserves in-place.
Reserve life			A measure of the productive life of an oil or natural gas property or a group of properties, expressed in years.
Royalty interest			An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
Standardized measure			The present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices used in estimating proved oil and natural gas reserves to the year-end quantities of those reserves in effect as of the dates of such estimates and held constant throughout the productive life of the reserves and deducting the estimated future costs to be incurred in developing, producing, and abandoning the proved reserves (computed based on year-end costs and assuming continuation of existing economic conditions). Future income taxes are calculated by applying the appropriate year-end statutory federal and state income tax rates with consideration of future tax rates already legislated, to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to proved oil and natural gas reserves.

Working interest			An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas from the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

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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 and midstream project, which could lead to a decline in our reserves.

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

•Development risks with our planned midstream project may cause cost overruns, delays or prevent completion of the projects, and even if completed, may not perform as anticipated.

•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 declare dividends.

•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.

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•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 the military conflict between Russia and Ukraine, the Israel-Hamas conflict, and the global response to such conflicts may negatively impact us.

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, occupational health and safety, and pipeline integrity management could adversely affect the cost, manner or feasibility of conducting our operations.

•We are responsible for the decommissioning, plugging, abandonment, and reclamation costs for our facilities.

•Increased regulation of our oil and natural gas assets as well as our planned midstream project 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.

•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, if any, may vary significantly both quarterly and annually.

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

•Available cash for dividends depends primarily on our cash flow and not solely on our profitability, which may prevent us from paying dividends, 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, on the one hand, and certain of our stockholders and their respective affiliates.

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PART I

Items 1 and 2. Business and Properties

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 ~~stable~~ cash flows ~~in the Permian Basin~~. 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 ~~while~~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 ~~the~~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.

~~See~~On ~~Note~~July 41, -2025, ~~Acquisitions~~the ofCompany ~~Oil~~completed ~~and~~the ~~Natural~~acquisition ~~Gas~~of ~~Properties~~100% inof the ~~Company's~~ownership ~~consolidated~~interests ~~financial~~of ~~statements~~Silverback inExploration II, LLC and its subsidiaries ("~~Item~~Silverback") ~~15.~~which ~~Exhibits~~own oil and ~~Financial~~natural ~~Statement~~gas ~~Schedules"~~assets ~~for~~and aoperations ~~full~~located ~~discussion~~primarily in the Yeso trend of the ~~2023~~Permian Basin in Eddy County, New Mexico (“Silverback Acquisition”). ~~and~~The ~~the~~acquisition ~~2024~~added ~~New~~approximately ~~Mexico~~40,000 ~~Asset~~net ~~Acquisition~~acres ~~(the~~directly ~~"2023~~adjacent to and ~~2024~~overlapping with the Company's existing core acreage primarily in Eddy County, New Mexico ~~Acquisitions")~~.

~~Other~~On ~~Developments~~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.

WeOn ~~believe~~December 3, 2025, the ~~successful~~Company ~~execution~~sold all of our membership interests in Dovetail Midstream, LLC, a wholly owned subsidiary of the Company's that holds certain midstream infrastructure projects in Eddy County, New Mexico, ~~development~~to ~~plan~~Targa isNorthern ~~dependent~~Delaware ~~upon~~LLC ~~maintaining~~("Targa") ~~operational~~for ~~control~~an ~~and~~aggregate ~~securing~~cash ~~reliable~~purchase ~~processing~~price ~~and~~of ~~downstream~~approximately ~~markets~~$111 million, subject to customary purchase price adjustments (the “Midstream Sale”). The Midstream Sale also provided for ~~our~~the ~~natural~~subsequent ~~gas~~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 ~~this~~the ~~plan~~Midstream Sale, the Company ~~signed~~amended aits long-term gas purchase agreement ("A&R Gas Purchase Agreement") for our New Mexico field with ~~a new midstream counterparty~~Targa, which includes dedicated acreage and a minimum volume commitment for a significant portion of the Company’s ~~oil~~natural ~~and~~ gas ~~assets~~production in New Mexico, ~~reimbursement~~with byan ~~the~~initial ~~Company~~15-year ofterm ~~construction~~from ~~costs~~the ~~incurred~~in-service bydate, ~~the~~which ~~midstream~~is ~~counterparty~~expected to ~~connect~~commence tobefore the ~~Company’s~~end ~~pipeline~~of ~~(subject~~2026. toCurrently, awe ~~monetary~~transport ~~cap~~all of ~~$18.7 million)~~our crude oil, natural gas and anNGLs ~~initial~~in ~~15-year~~New ~~term~~Mexico ~~from~~to ~~the~~a ~~in-service~~few ~~date.~~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.

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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 ~~2023 and 2024~~ New Mexico Acquisitions. ~~Riley~~Our ~~Permian’s~~ acreage in Yoakum County ~~offsets~~is adjacent to legacy Permian Basin San Andres fields, including the Wasson and Brahaney fields, ~~with~~where conventional development incommenced ~~the area beginning~~ in the 1930s. ~~and~~Horizontal ~~1940s.~~San WeAndres ~~believe~~wells ~~the~~drilled ~~horizontal~~to ~~San~~date ~~Andres~~by ~~wells~~the weCompany and offset operators have ~~drilled to date have~~ delineated our acreage in the area. In Eddy County, New Mexico, our acreage ~~offsets~~is adjacent to legacy Permian Basin Abo, Yeso, and San Andres fields, including the Red Lake and Loco Hills fields, which have been producing ~~since~~from ~~horizontal~~vertical ~~development~~wells insince the ~~area~~1950s ~~began in 2007~~ and ~~2008, with production~~ from ~~vertical~~horizontal ~~wells~~development ~~dating~~since ~~to the 1950s~~2007. Based on the ~~close~~ proximity of this acreage to ~~these~~established ~~productive~~producing fields, ~~combined~~and ~~with~~ the performance of horizontal Yeso wells wedrilled ~~and~~by ~~offset~~the ~~operators~~Company ~~have~~and ~~drilled~~offset ~~to date~~operators, we believe weour ~~have~~Eddy ~~significantly~~County ~~delineated~~acreage ~~our~~is ~~acreage~~significantly delineated.

As of December 31, ~~2024~~2025, we had 5897,~~270~~538 net acres and a total of ~~612~~873 net producing wells. We operated 96% of our net production for the year ended December 31, ~~2024~~2025, and have an average working interest of 9185% in our operated wells. Our average net daily production during the year ended December 31, ~~2024~~2025, was approximately 2229,~~546~~205 Boe/d.

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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 ~~as of December 31, 2024, and 2023~~:

December 31,

2024

2023

2025

2024

2023

Proved Developed Producing Reserves:(1)

Oil (MBbls)

4042,~~111~~907

3640,~~731~~111

36,731

Natural Gas (MMcf)

~~103~~124,~~337~~165

71103,~~671~~337

71,671

NGLs (MBbls)

1923,~~312~~109

1119,~~502~~312

11,502

Proved Developed Producing Reserves (MBoe)

7686,~~646~~710

6076,~~178~~646

60,178

Proved Undeveloped Reserves:

Oil (MBbls)

2631,~~424~~440

2926,~~577~~424

29,577

Natural Gas (MMcf)

5882,~~902~~492

5258,~~277~~902

52,277

NGLs (MBbls)

1015,~~715~~516

910,~~247~~715

9,247

Proved Undeveloped Reserves (MBoe)

4660,~~956~~705

4746,~~537~~956

47,537

Total Proved Reserves:

Oil (MBbls)

6674,~~535~~347

66,~~308~~535

66,308

Natural Gas (MMcf)

~~162~~206,~~239~~657

~~123~~162,~~948~~239

123,948

NGLs (MBbls)

3038,~~027~~625

2030,~~749~~027

20,749

Total Proved Reserves (MBoe)

~~123~~147,~~602~~415

~~107~~123,~~715~~602

107,715

_____________________

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

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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 ~~for the year ended December 31, 2024~~ (in MBoe):

Proved undeveloped reserves at December 31, 2023						47,537
Acquisitions						3,028
Conversions						(6,186)
Extensions and discoveries						7,934
Revisions						(5,357)
Proved undeveloped reserves at December 31, 2024						46,956
Acquisitions						3,312
Divestitures						(386)
Conversions						(10,844)
Extensions and discoveries						22,991
Revisions						(1,324)
Proved undeveloped reserves at December 31, 2025						60,705

PUDs ~~decreased~~increased by a net 013.67 MMBoe for the year-ended December 31, ~~2024~~2025, as compared to the year-ended December 31, ~~2023~~2024. PUDs increased by 323.0 MMBoe ~~from~~due ~~acquired~~to ~~reserves~~extensions ~~obtained~~and indiscoveries, andue ~~acreage~~primarily ~~swap.~~from ~~PUDs~~drilling ~~decreased~~activity byduring ~~6.2~~the ~~MMBoe~~year, ~~due~~which toallowed ~~conversions,~~for ~~and~~the webooking ~~incurred~~of ~~approximately~~adjacent ~~$37~~PUDs ~~million~~for tolocations ~~convert~~that ~~these~~were ~~6.2~~previously ~~MMBoe~~classified ofas ~~PUDs~~unproved toreserves ~~proved~~or ~~developed~~not ~~producing~~at ~~(PDP) reserves~~all. PUDs also increased by 73.93 MMBoe ~~due~~from toacquired ~~extensions~~reserves ~~and~~obtained ~~discoveries,~~in ~~due~~the ~~primarily~~Silverback ~~from~~Acquisition, ~~drilling~~partially ~~activity~~offset ~~during~~by ~~the~~a ~~year,~~divestiture ~~which~~due ~~allowed~~to ~~for~~our ~~the~~Viking ~~booking~~Sale of ~~adjacent~~0.4 ~~PUDs~~MMBoe, ~~for~~a ~~locations~~net ~~that~~2.9 ~~were~~MMBoe ~~previously booked as unproved reserves or not at all~~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 ~~proved~~PUDs ~~undeveloped reserves~~ of 51.43 MMBoe, which included 103.68 MMBoe of negative revisions partially offset by 5.2.5 MMBoe of positive revisions. Our negative revisions were primarily attributable to 52.79 MMBoe ~~related~~of ~~to type-curve forecast changes. Negative revisions also included~~ development plan changes which resulted in the removal of ~~PUD~~PUDs ~~locations representing 4.2 MMBoe of PUD reserves~~ from our 5-year forecast, 0.57 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 ~~forecasted~~type curve forecasts of natural gas and NGLs sales volumes of 32.43 MMBoe based on improved ~~gas~~well ~~processing~~performance ~~capacity~~ in addition to decreases in operating expenses ~~and midstream fees~~ that caused positive revisions of 10.82 MMBoe.

PUDs will be converted from undeveloped to developed with successful development and as the applicable wells begin production. As of December 31, ~~2024~~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, ~~2024~~2025, were approximately $~~279~~285 million, which we expect to ~~finance~~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, ~~2024~~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 ~~the~~our reserve estimates is our ~~Reservoir~~Senior ~~Engineering~~ Manager of Corporate Reserves. Our ~~Reservoir~~Senior ~~Engineering~~ Manager of Corporate Reserves has over 1718 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~~ 8

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~~covered~~Internal byControls 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.

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 ~~Reservoir~~Senior ~~Engineering~~ 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, ~~2024~~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.

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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. WeAll dowells ~~not~~drilled ~~have~~are ~~any~~classified ~~natural~~as ~~gas~~oil wells, ~~therefore~~(with ~~the~~associated ~~information~~natural ~~set~~gas ~~forth~~and inNGLs); ~~the~~we ~~table~~did ~~below~~not ~~only~~drill ~~pertains~~any towells ~~oil~~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 ~~for the years ended December 31, 2024, 2023, and 2022~~:

	Year Ended December 31,
	2024		2023		2022
	2025		2024		2023
	Gross	Net(1)	Gross	Net(1)	Gross	Net(1)
Development Wells:
Productive	2125	19.30	2421	1819.23	1724	1318.82
Dry	—	—	—	—	—	—
Exploratory Wells:
Productive	—	—	—	—	—	—
Dry (2)	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total Wells:
Productive	2125	19.30	2421	1819.23	1724	1318.82
Dry	—	—	—	—	—	—

_____________________

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

~~(2)Excludes~~As anof ~~exploratory~~December ~~well~~31, ~~suspended~~2025, aswe ofhad ~~September~~11 ~~30,~~gross ~~2021,~~(11.0 ~~and~~net) ~~subsequently~~wells ~~expensed~~ in the ~~fourth~~process ~~quarter~~ of ~~2023~~drilling or active completions stages.

AsWe operated 96% of our production for the year ended December 31, ~~2024~~2025. As operator, we ~~had~~design 15and ~~gross~~manage ~~(10.9~~the ~~net)~~development of our wells inand supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide the ~~process~~majority of ~~drilling~~the orequipment ~~active~~and ~~completions~~personnel ~~stages~~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.

We operated 96% of our production for the year ended December 31, 2024. 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, ~~2024~~2025:

Developed Acreage(1)		Undeveloped Acreage(2)		Total Acreage
Gross(3)	Net(4)	Gross(3)	Net(4)	Gross(3)	Net(4)
72,862	55,315	5,742	2,955	78,604	58,270
136,182	92,380	14,690	5,158	150,872	97,538

_____________________

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

(2)Undeveloped acreage ~~are~~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 9596% of our total net acreage is held by production or company owned minerals, and 0.2515% 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~~company ~~lease~~owned ~~is renewed or extended under continuous drilling provisions prior to the primary term expiration dates~~minerals, ~~the~~unless ~~leases~~production ~~will~~is ~~expire~~established 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~~

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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, ~~2024~~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:

Net Undeveloped Acreage
2025	2026	2027
2026	2027	2028
1,211	932	660
1,219	1,299	1,313

As of December 31, ~~2024~~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 5962% fee and state leasehold with the remaining 4138% 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, ~~2024~~2025, ~~2023,~~2024 and ~~2022~~2023:

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Year Ended December 31,

2024

2023

2022

2025

2024

2023

Production Data, net:

Oil (MBbls)

Champions

4,~~170~~086

34,~~658~~170

3,~~075~~658

Red Lake

12,~~237~~168

~~930~~1,237

—930

Other

~~112~~74

~~214~~112

~~142~~214

Total

56,~~519~~328

45,~~802~~519

34,~~217~~802

Natural gas (MMcf)

Champions

35,~~918~~829

3,~~589~~918

3,~~198~~589

Red Lake

35,~~513~~804

23,~~179~~513

—2,179

Other

5336

9753

3197

Total

711,~~484~~669

57,~~865~~484

35,~~229~~865

NGLs (MBbls)

Champions

~~811~~1,283

~~526~~811

~~435~~526

Red Lake

~~659~~1,096

~~451~~659

—451

Other

168

2916

929

Total

12,~~486~~387

1,~~006~~486

~~444~~1,006

Total (MBoe)

Champions

56,~~634~~341

45,~~783~~634

4,~~043~~783

Red Lake

24,~~481~~232

12,~~744~~481

—1,744

Other

~~137~~87

~~259~~137

~~156~~259

Total

810,~~252~~660

68,~~786~~252

46,~~199~~786

Daily combined volumes (Boe/d)

Champions

1517,~~393~~371

1315,~~102~~393

1113,~~077~~102

Red Lake

611,~~779~~593

46,779

—4,779

Other

~~374~~241

~~709~~374

~~428~~709

Total

2229,~~546~~205

1822,~~590~~546

1118,~~505~~590

Daily oil volumes (Bbls/d)

Champions

11,~~393~~195

1011,~~022~~393

810,~~425~~022

Red Lake

35,~~380~~940

23,~~548~~380

—2,548

Other

~~306~~202

~~586~~306

~~389~~586

Total

1517,~~079~~337

1315,~~156~~079

813,~~814~~156

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	Year Ended December 31,
	2024		2023		2022
	2025		2024		2023
Average Realized Prices:(1)
Oil ($ per Bbl)	$	7462.1095	$	7574.6210	$	9275.8662
Natural gas ($ per Mcf)	$	(0.1928)	$	(0.4519)	$	30.3345
NGLs ($ per Bbl)	$	(1.5327)	$	61.8753	$	226.2287
Average Realized Prices, including derivative settlements:(1)(2)
Oil ($ per Bbl)	$	7365.6746	$	7173.9367	$	71.7593
Natural gas ($ per Mcf)	$	(0.3722)	$	0.5337	$	10.0653
NGLs ($ per Bbl)(3)	$	(1.5327)	$	61.8753	$	226.2287
Average Operating Costs per Boe:
Lease operating expenses	$	8.6621	$	8.6766	$	78.7367
Production and ad valorem taxes	$	32.5773	$	3.7757	$	43.5977

_____________________

(1)The Company's oil, natural gas and NGL sales are presented net of ~~gathering,~~GP&T ~~processing and transportation~~ 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 ~~our~~new ~~drilling~~wells ~~and~~turned ~~completion~~to ~~activity~~sales asand ~~well~~additional asproduction from our ~~2024~~Silverback ~~New Mexico Asset~~ Acquisition, we increased our average net production from 1822,~~590~~546 Boe/d for the year ended December 31, ~~2023~~2024, to an average net production of 2229,~~546~~205 Boe/d for the year ended December 31, ~~2024~~2025. During the year ended December 31, ~~2024~~2025, our production was approximately 6760% oil, 1518% natural gas and 1822% NGLs.

Productive Wells

As of December 31, ~~2024~~2025, we produced from ~~782~~1,231 gross (~~612~~873 net) total wells, which included both operated and non-operated wells.

Producing Wells

Gross Wells

Average Working Interest

Operated

~~657~~974

9185

Non-Operated

~~125~~257

1317

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

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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 ~~year~~years ended December 31, ~~2024~~2025, 2024 and 2023, an additional purchaser accounted for 1030%, or22% ~~more~~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. ~~Further~~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 ~~Midstream~~, ~~LLC~~who ~~("Stakeholder")~~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, ~~2024~~2025, the Company had less than ~~seven~~five years remaining on our contract with Stakeholder.

AtAs ~~our~~part ~~Red~~of ~~Lake~~the ~~field~~Midstream inSale, the Company entered into the A&R Gas Purchase Agreement for our New Mexico field with Targa, wewhich ~~currently~~includes ~~transport~~dedicated ~~all~~acreage ofand ~~our~~a ~~crude~~minimum ~~oil~~volume tocommitment for a ~~few~~significant ~~purchasers.~~portion ~~Our~~of the Company’s natural gas ~~and~~production ~~NGLs~~in ~~are~~New ~~gathered~~Mexico, ~~through~~with ~~one~~an ~~midstream~~initial ~~provider.~~15-year ~~Our~~term ~~midstream~~from ~~provider~~the ~~also~~in-service ~~treats~~date, ~~and~~which ~~processes~~is ~~all~~expected ofto ~~our~~commence ~~natural~~before ~~gas~~the ~~and~~end ~~NGLs~~of 2026. AsCurrently, we transport all of ~~December~~our ~~31,~~crude ~~2024~~oil, ~~the~~natural ~~Company’s~~gas ~~contract~~and ~~with~~NGLs ~~this~~in ~~service~~New ~~provider~~Mexico ~~was~~to on a ~~month~~few toother ~~month basis~~purchasers.

We believe the successful execution of the Company's New Mexico development plan is dependent upon maintaining operational control and securing reliable processing and downstream markets for our natural gas. As part of this plan, the Company signed a long-term gas purchase agreement for our New Mexico field with a new midstream counterparty, which includes dedicated acreage for a significant portion of the Company’s oil and gas assets in New Mexico, reimbursement by the Company of construction costs incurred by the midstream counterparty to connect to the Company’s pipeline (subject to a monetary cap of $18.7 million) and an initial 15-year term from the in-service date. In conjunction with the agreement, the Company intends to construct, own and operate low and high-pressure gathering lines and compression facilities that will connect to our new high capacity 20-inch natural gas pipeline to be constructed by the Company and designed to handle gas volumes of up to 150 MMcf per day. We currently anticipate the in-service date will be before the end of 2026. The Board of Directors approved an aggregate of approximately $130 million in capital expenditures to complete these initial projects of our midstream development plan. 14

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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 ~~statutory~~laws ~~provisions~~and regulations regulating the development and production of oil and natural gas, including, for example, land use, conservation, well construction, ~~and~~ protection of the environment, ~~and of~~ 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 ~~Production~~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.

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 15

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~~competitors~~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 ~~oil~~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 ~~natural~~plugged—has ~~gas~~recently ~~industry~~been ~~are~~expressed ~~subject~~and, in some cases, spurred calls for increasing the required amounts of financial assurance to more accurately reflect the ~~same~~current, ~~regulatory~~actual ~~requirements~~costs of plugging and ~~restrictions~~abandonment. For example, in October 2025, the New Mexico Oil Conservation Commission (“NMOCC”) conducted a hearing to consider (“NMOCC”) proposed rules that ~~affect~~if ~~REPX~~adopted would substantially increase bonding requirements and introduced higher, per well bonding requirements if a certain percentage of an operator’s ~~operations~~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.

~~Regulation~~The offailure ~~Sales~~to comply with the rules and ~~Transportation~~regulations of ~~Oil~~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 $1,000,000 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 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 16

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~~requirements~~intrastate ~~under~~transportation ~~Order~~and ~~704,~~wholesale ~~described~~sales ~~below,~~of ~~which mandates that certain~~ natural gas ~~market~~may ~~participants~~also ~~report~~be ~~aggregate~~affected ~~annual~~directly ~~transaction~~or ~~data~~indirectly toby ~~aid~~laws inenacted ~~market~~by ~~transparency.~~Congress ~~The anti-market manipulation rule~~ and ~~enhanced~~by ~~civil penalty authority reflect an expansion of~~ FERC’s ~~NGA enforcement authority~~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.

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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.

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operations; for example, they 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) govern the disposal and recycling of waste and 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 worker protection measures; (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. Further, 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 18

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~~regulations regarding oil and natural gas wastes was not necessary at that time~~substances”. ~~But,~~REPX ~~should~~is ~~future~~able ~~rulemakings~~to orcontrol ~~legal~~directly ~~challenges~~the ~~result~~operation ~~in a loss~~ of ~~the~~only ~~RCRA~~those ~~hazardous-waste~~wells ~~exclusion~~with ~~for~~respect ~~drilling~~to ~~fluids,~~which ~~produced~~REPX ~~waters~~acts ~~and~~as ~~related~~operator. ~~wastes,~~Notwithstanding REPX’s ~~costs~~lack toof ~~manage~~direct ~~and~~control ~~dispose~~over ofwells ~~generated~~operated ~~wastes~~by ~~could increase~~others, ~~which~~the ~~could~~failure ~~have~~of aan ~~material~~operator ~~adverse~~other ~~effect~~than on REPX’s ~~results~~to ofcomply ~~operations~~with ~~and~~applicable ~~financial~~environmental ~~position.~~regulations Inor ~~addition, in~~ the ~~course~~failure of ~~REPX’s~~a ~~operations,~~facility ~~REPX~~receiving ~~generates~~hazardous ~~some~~substances ~~amounts~~for oftreatment ~~ordinary~~or ~~industrial~~disposal ~~wastes,~~to ~~such~~manage asthe ~~paint~~substances ~~wastes,~~properly ~~waste solvents~~may, ~~laboratory~~in ~~wastes~~certain ~~and~~circumstances, ~~waste compressor oils that may~~ be ~~regulated~~attributed asto ~~hazardous~~REPX ~~wastes~~and ifresult ~~such~~in ~~wastes~~CERCLA ~~are~~or ~~listed~~comparable asfederal ~~hazardous wastes~~ or ~~have~~state ~~hazardous characteristics~~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. 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 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.19

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~~operations,~~removing ~~spill~~the ~~prevention~~“significant ~~practices,~~nexus” ~~discharge~~standard orfrom ~~drainage~~the ~~controls~~provisions regarding tributaries, adjacent wetlands, and intrastate lakes and ponds. The EPA initiated an update to the ~~personnel,~~WOTUS ~~equipment~~definition in November of 2025 and ~~resources~~the atproposed rule is under consideration following closure of the ~~facility~~public ~~that~~comment ~~are~~period ~~used~~in late 2025. To the extent any litigation or future amendments to ~~prevent~~the ~~oil~~rule ~~spills~~expand ~~from~~the ~~reaching~~scope ~~navigable~~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 ~~regulated~~water ~~waters~~features or ~~adjoining~~in ~~shorelines,~~connection with stream crossings and ~~reviewed~~preparation atand ~~least~~implementation ~~every~~of ~~five~~oil ~~years~~SPCC plans.

~~Pursuant~~The primary federal law related specifically to ~~CWA~~oil ~~laws~~spill ~~and~~liability ~~regulations~~is the Oil Pollution Act of 1990 (“OPA”), ~~REPX~~which ~~may~~amends ~~also~~and beaugments ~~required~~the tooil ~~obtain~~spill provisions of the CWA and ~~maintain~~imposes ~~approvals~~certain orduties ~~permits~~and liabilities on certain “responsible parties” for the ~~discharge~~prevention of ~~wastewater,~~oil ~~including~~spills ~~produced~~and ~~water,~~remediation orof ~~storm~~damages ~~water.~~resulting ~~Obtaining~~from ~~permits~~such ~~has~~spills ~~the~~in ~~potential~~or tothreatening ~~delay~~waters of the ~~development~~United States or adjoining shorelines. In addition, operators of certain oil and natural gas ~~projects.~~facilities ~~These~~must ~~laws~~develop, implement and ~~any~~maintain ~~implementing~~facility ~~regulations~~response ~~provide~~plans, conduct annual spill training for ~~administrative,~~certain ~~civil~~employees and ~~criminal~~provide ~~penalties~~varying ~~for~~degrees ~~any~~of ~~unauthorized~~financial ~~discharges~~assurance. Under the OPA, owners or operators of ~~oil~~a ~~and~~facility, ~~other~~vessel ~~substances~~or ~~and~~pipeline ~~may~~that ~~impose~~is a source of an oil discharge or that poses a substantial ~~potential~~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 ~~costs~~entire cost of ~~removal,~~cleanup ~~remediation~~ 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. Additionally, 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.

InLegal ~~addition,~~disputes ~~several~~may ~~cases~~arise ~~have~~based ~~recently put a spotlight~~ on ~~the~~allegations 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~~disposal ~~these~~well ~~cases~~operations ~~engendered~~have ~~two~~caused ~~petitions~~damage ~~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~~or aneighboring ~~direct~~properties ~~hydrological~~or ~~connection~~otherwise toviolated ~~jurisdictional~~state ~~surface~~or ~~water, which hydrological connections should be considered “direct,” and whether such discharges would be better addressed through other~~ federal orrules ~~state~~regulating ~~programs~~waste disposal. InThese ~~April,~~developments ~~2020,~~could ~~the~~result ~~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~~regulation, ~~following~~restriction ~~the ruling, in January 2021, new guidance~~ on the ~~ruling,~~use ~~but~~of ~~that~~injection ~~guidance~~wells ~~was~~by ~~later~~REPX ~~rescinded~~or by ~~EPA.~~commercial Ondisposal ~~November~~well ~~20,~~vendors ~~2023,~~whom ~~EPA~~REPX ~~issued draft guidance outlining the factors that~~ may beuse ~~considered~~from ~~when~~time ~~evaluating whether discharges through groundwater may be the “functional equivalent” of a direct discharge, and thereby subject~~ to ~~regulation~~time ~~under the CWA National Pollutant Discharge Elimination System Permit Program (which permits point sources~~ to ~~discharge~~dispose ~~specified amounts~~ of ~~pollutant(s) to waters of the United States under specified conditions~~wastewater, and ~~describes~~increased ~~the~~costs ~~types~~ of ~~information~~compliance, ~~that~~which ~~should~~could behave ~~used~~a inmaterial ~~determination).~~adverse ~~Comments~~effect 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~~REPX’s ~~ruling~~capital inexpenditures ~~County~~and ofoperating ~~Maui~~costs, ~~Hawaii~~financial v.condition, ~~Hawaii~~and ~~Wildlife~~results ~~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~~operations.

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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.”

22Compliance 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

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~~and~~rule 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,~~2022 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~~requires ~~the~~oil ~~reduction of volatile organic compound emissions from certain fractured~~ and ~~refractured~~ natural gas ~~and,~~producers in ~~2016,~~counties ~~oil~~that ~~wells for which well completion operations~~ are ~~conducted~~at ~~(i.e.,~~risk ~~use~~of ~~reduced~~non-attainment ~~emission~~of ~~completions,~~federal ~~also~~ozone ~~known~~standards ~~as “green completions”), referred~~ to ~~as New Source Performance Standards ("NSPS") subparts OOOO and OOOOa~~, ~~respectively.~~among ~~These~~other ~~regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors~~things, ~~pneumatic~~check ~~controllers,~~emission ~~storage~~rates ~~vessels,~~ and ~~under~~have ~~the~~those ~~NSPS~~calculations ~~Subpart~~certified ~~OOOOa~~by regulations, well-site and compressor station components (fugitive emissions). More recently, EPA finalized on March 8, 2024, additional final NSPS OOOO program final rules—referred to as Subparts OOOOb and OOOOc—which, became effective May 7, 2024, and are expected to have a ~~significant~~qualified ~~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~~engineer, ~~modified,~~perform ~~and~~enhanced ~~reconstructed~~checks ~~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 effectleaks, ~~future~~repair ~~implementation~~those ~~and~~leaks ~~the~~within ~~ultimate~~15 ~~scope~~days of ~~VOC and methane emissions for the oil and gas production~~discovery, ~~transmission,~~ and ~~storage~~maintain ~~industry~~records ~~segments~~to ~~are~~demonstrate ~~uncertain~~continuous ~~at this time and could be modified further as a result of ongoing rulemakings and expected legal challenges~~compliance. 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, 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 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 final rule to implement the fee requirements, “Waste Emissions Charge for Petroleum and Natural Gas Systems,” was published on November 18, 2024, and took effect on January 17, 2025. 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

23In 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

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~~proposed~~June ~~amendments~~10, 2024. ~~More~~In ~~recently~~September of 2024, ~~EPA~~the ~~proposed~~United ~~and~~States ~~has~~District ~~since~~Court ~~announced~~for ~~final~~the ~~rules~~District toof beNorth ~~codified~~Dakota asgranted ~~NSPS~~a ~~Subparts~~motion ~~OOOOb~~for ~~and~~preliminary ~~OOOOc~~injunction ~~that~~filed ~~expand~~by the ~~OOOO~~plaintiff ~~regulatory~~states ~~program.~~of ~~For~~North ~~example~~Dakota, ~~notably~~Texas, ~~the~~Montana, ~~NSPS~~Wyoming, ~~Subpart~~and ~~OOOOc~~Utah, ~~rules~~which ~~include~~prohibits ~~emissions~~BLM ~~guidelines~~"from toenforcing ~~assist states in~~ the ~~development~~2024 of[Waste ~~plans~~Prevention] toRule ~~regulate~~against ~~methane~~the ~~emissions~~[plaintiff ~~from~~states] ~~certain~~pending ~~existing~~the ~~sources,~~outcome ~~which~~of ~~had~~this ~~not~~litigation." ~~previously~~The ~~been~~litigation ~~regulated~~is ~~under~~currently ~~NSPS~~being ~~Subpart~~held ~~OOOO~~in ~~programs.~~abeyance ~~Legal~~in ~~challenges,~~response ~~including by states,~~ to the ~~recently~~BLM ~~finalized~~'s ~~NSPS~~request ~~Subparts~~to ~~OOOOb~~do ~~and~~so ~~OOOOc~~under ~~rules~~the ~~have~~second ~~followed~~Trump administration. ~~Further~~and, ~~the~~in ~~Trump~~December ~~presidential~~of ~~administration~~2025, ~~may~~BLM ~~make~~published ~~efforts~~an extension to ~~rollback~~December orof ~~revise~~2026 ~~these~~of ~~rules~~enforcement indeadlines ~~connection~~applicable ~~with~~to ~~its~~leak ~~focus~~detection onand ~~promotion~~repair, ~~of oil~~ and ~~natural~~flares ~~gas~~flowing ~~production. Thus~~1,050-6,000 ~~although~~mcf/month. ~~the~~BLM ~~rules~~is ~~are~~delaying ~~currently~~enforcement inbecause ~~effect,~~it ~~the~~is ~~ultimate~~considering ~~scope~~revisions ofto these ~~regulations~~two ~~remains uncertain~~regulations. ~~Compliance~~The ~~with~~outcome ~~these~~of ~~rules~~the ~~requires~~BLM's ~~enhanced~~potential ~~record-keeping~~revisions ~~practices,~~to the ~~purchase~~Waste ofPrevention ~~new~~Rule ~~equipment~~and ~~such~~the asoutcome ~~optical~~of ~~gas~~the ~~imaging~~North ~~instruments~~Dakota tolitigation ~~detect~~could ~~leaks~~affect ~~and~~the ~~increased~~validity ~~frequency~~and substance of ~~maintenance~~the ~~and~~Waste ~~repair~~Prevention ~~activities~~Rule toin ~~address~~the ~~emissions~~plaintiff ~~leakage~~and other states. ~~The~~These ~~rules~~newly ~~will~~proposed ~~also~~rules, ~~likely~~as ~~require~~may ~~hiring~~be ~~additional~~amended ~~personnel~~under tothe ~~support~~Trump ~~these~~administration, ~~activities~~could orresult ~~the~~in ~~engagement~~increased ofcompliance ~~third~~costs ~~party~~on ~~contractors~~REPX’s tooperations ~~assist~~on ~~with~~federal and ~~verify~~American ~~compliance~~Indian lands.

~~The~~At ~~BLM also finalized similar rules regarding~~ the ~~control~~State 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. Howeverlevel, ~~due to subsequent BLM revisions and multiple legal challenges,~~ the ~~rules~~New ~~were~~Mexico ~~never~~legislature ~~fully~~is ~~implemented,~~currently ~~and~~considering ina ~~October 2020~~bill, ~~the~~referred ~~November~~to ~~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~~Clear ~~gas~~Horizons ~~that~~Act” ~~is consumed~~ or ~~lost~~Senate byBill ~~venting~~18, ~~flaring,~~that orwould ~~negligent~~require ~~releases~~45% ~~through~~less ~~any~~GHG ~~equipment~~emissions ~~during~~by ~~upstream operations~~2030,” ~~the~~as ~~BLM~~compared ~~adopted~~to ~~the~~2005 ~~Waste~~levels; ~~Prevention,~~75% ~~Production~~less ~~Subject~~by to2040; ~~Royalties,~~ and ~~Resource~~100% ~~Conservation~~less ~~Rule~~by ~~(the~~2050 ~~"Waste Prevention Rule") in April of 2024~~ and ~~it went into effect on June 10, 2024~~thereafter. InThe ~~September~~imposition of ~~2024,~~substantial ~~the~~GHG ~~United~~emission ~~States~~reduction ~~District~~mandates ~~Court~~on ~~for~~oil ~~the~~and ~~District~~gas ofoperations ~~North~~in ~~Dakota~~New ~~granted~~Mexico amay ~~motion~~require ~~for~~significant ~~preliminary~~investment ~~injunction~~in ~~filed~~additional bypollution ~~the~~control ~~plaintiff~~or ~~states~~gas ofcapture ~~North Dakota~~equipment, ~~Texas,~~as ~~Montana,~~well ~~Wyoming,~~as ~~and~~strain ~~Utah, which prohibits BLM "from enforcing~~ the ~~2024~~supply ~~[Waste Prevention] Rule against the [plaintiff states] pending the outcome~~ of ~~this~~such ~~litigation."~~equipment ~~The~~and ~~outcome of~~ the ~~North~~availability ~~Dakota litigation could affect the validity and substance~~ of ~~the~~qualified ~~Waste~~engineering ~~Prevention~~personnel, ~~Rule~~which ~~in the plaintiff and other states. These newly proposed rules~~ could result in increased capital, employee, and compliance costs onfor REPX’s operations onin ~~federal~~New ~~and Indian lands~~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.

~~Certain~~Governmental ~~governmental~~ reviews have ~~recently~~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

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~~result~~concerns inover ~~more~~scarcity ~~frequent~~of ~~or more severe impacts:~~ water ~~withdrawals for fracturing in times~~ and/or ~~areas~~injection ofoptions. ~~low~~Following ~~water~~a ~~availability;~~public ~~surface~~input ~~spills~~period, ~~during~~ the ~~management~~EPA ofissued ~~fracturing~~a ~~fluids,~~final ~~chemicals~~report orin ~~produced~~May ~~water;~~2020, ~~injection~~which, ofat ~~fracturing~~the ~~fluids~~time, ~~into~~found ~~wells~~mixed ~~with~~support ~~inadequate~~from ~~mechanical~~stakeholders ~~integrity;~~regarding ~~injection~~additional ofproduced ~~fracturing~~water ~~fluids directly into groundwater resources;~~ discharge ofoptions. ~~inadequately~~These ~~treated~~ongoing ~~fracturing wastewater to surface waters; and disposal~~ or ~~storage~~proposed ofstudies ~~fracturing~~could ~~wastewater~~spur ininitiatives ~~unlined~~to ~~pits.~~further ~~Since~~regulate ~~the report did not find a direct link between~~ hydraulic fracturing ~~itself~~under ~~and~~the ~~contamination~~federal ~~of groundwater resources~~SDWA, ~~this~~CWA ~~years-long~~or ~~study~~other ~~report~~regulatory ~~does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level~~mechanisms. ~~More~~For ~~recently~~example, the EPA ~~initiated~~announced ain ~~study~~March of2025 ~~Oil~~that ~~and~~it ~~Gas~~plans ~~Extraction~~to ~~Wastewater~~revise ~~Management in 2018 that~~ the ~~agency~~effluent ~~characterizes~~limitations asguidelines afor ~~“holistic~~oil ~~look” at how produced water is regulated~~ and ~~managed~~gas bywastewater ~~the~~discharges ~~EPA,~~to ~~states,~~provide ~~and~~regulatory ~~tribes,~~flexibility and ~~has~~help ~~sought~~facilitate ~~input~~beneficial ~~on these issues from other stakeholders such as academics~~use, ~~non-governmental organizations,~~ and ~~industry.~~such Aregulation ~~primary~~would ~~focus~~likely ofimpose ~~the~~permitting ~~study is to evaluate whether federal regulations allowing for more discharge options would be beneficial~~requirements, ~~for~~potentially ~~example,~~creating delays in ~~addressing~~the ~~areas~~development ~~with~~of ~~concerns~~and ~~over~~increased ~~scarcity~~costs of ~~water~~compliance ~~and/or~~for ~~injection~~REPX’s ~~options~~operations. ~~Following~~At athe ~~public~~state ~~input period~~level, ~~the~~New ~~EPA~~Mexico issued arules ~~final report~~ in ~~May~~July ~~2020,~~2025 ~~which~~governing ~~found~~pilot ~~mixed~~projects ~~support~~for ~~from~~the ~~stakeholders~~reuse ~~regarding~~of ~~additional~~oil ~~produced~~and ~~water~~gas ~~discharge~~wastewater ~~options.~~and ~~The~~prohibiting ~~EPA is still determining what, if~~ any, ~~next~~discharge ~~steps are appropriate regarding produced water management in light~~ of ~~the~~that ~~report.~~wastewater ~~These ongoing or proposed studies could spur initiatives~~ to ~~further~~surface ~~regulate hydraulic fracturing under the federal SDWA, CWA~~ or ~~other regulatory mechanisms~~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, ~~as threatened~~ or ~~endangered~~could ~~are known to exist and where other species that~~ potentially ~~could~~ be listed, as threatened or endangered under the ESA ~~may~~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.

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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, ~~2024~~2025, we employed ~~103~~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.

~~Diversity and Inclusion~~ 25

WeTable ~~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. Our employment decisions are based on merit and qualifications. Contents

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 ~~for Riley Permian~~. The Company maintains a culture of continuous improvement in safety and environmental practices, supports aits ~~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.

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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.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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.

•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.

Filing Compare · Riley Exploration Permian, Inc.